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.
As defined by the U.S. Federal Energy Regulatory Commission (U.S. FERC), low-permeability ("tight") gas reservoirs have an average in-situ permeability of 0.1 md or less. Others have placed the upper limit at 1 md. Estimates of ultimate recovery from these resources vary widely and depend chiefly on assumptions of wellhead gas price. Methods for estimating gas reserves in moderate- to high-permeability reservoirs are unreliable in very-low-permeability reservoirs. The unreliability can be attributed to the geologic setting in which these reservoirs occur and the completion methods required to make them commercial.
Actually, the definition of a tight gas reservoir is a function of many factors, each relating to Darcy's law. The main problem with tight gas reservoirs is that they do not produce at economic flow rates unless they are stimulated--normally by a large hydraulic fracture treatment. Eq. 7.1 illustrates the main factors controlling flow rate.
Tight gas is the term commonly used to refer to low permeability reservoirs that produce mainly dry natural gas. Many of the low permeability reservoirs that have been developed in the past are sandstone, but significant quantities of gas are also produced from low permeability carbonates, shales, and coal seams. Production of gas from coal seams is covered in a separate chapter in this handbook. In this chapter, production of gas from tight sandstones is the predominant theme. However, much of the same technology applies to tight carbonate and to gas shale reservoirs. Tight gas reservoirs have one thing in common--a vertical well drilled and completed in the tight gas reservoir must be successfully stimulated to produce at commercial gas flow rates and produce commercial gas volumes. Normally, a large hydraulic fracture treatment is required to produce gas economically.
The objective of the project is to reconcile and quantify the impact of geological and completion variables that cause significant EUR differences in two recent wells drilled and completed in the Uteland Butte member of the Green River formation in Uinta Basin, Utah. While the geology and reservoir conditions are similar for both wells, the completion design and parameters are different (Ball-and-Sleeve vs. Plug-and-Perf, job size, treatment rates, well length, etc.).
The Asset Team uses a structured workflow consisting of several modeling tools: Rate-Transient-Analysis (RTA), Frac Modeling (FM) and Reservoir Simulation (RS) to address and quantify the impact of each variable: Job size, Treatment Rate, Frac count per Stage, Well Length and the effect of clays.
The workflow began with a performance evaluation of the high EUR well (Plug-and-Perf, large job) with RTA and Frac modeling; followed by history-match and prediction of the EUR with the RS model. In the subsequent workflow, a single variable is changed in each modeling step, while others are held constant -- as such, the EUR impact for each variable can be quantified. The result from each step is calibrated with the actual performance observed in the field.
This model-based approach successfully quantified the production impact of each variable. Subsequently, the key drivers can be determined which explains the estimated EUR difference between the two wells. This work drives us to conclude that due to varying pressure, PVT and lithology across the field, different completion designs shall be utilized. The team has gained valuable insight on how to implement different completion techniques with varying job size and design for the basin. Currently, these results are used to drive the well designs and approval; with the long-term objective of optimizing the Field Development Plan.
Cudjoe, Sherifa (University of Kansas) | Barati, Reza (University of Kansas) | Marshall, Craig (University of Kansas) | Goldstein, Robert (University of Kansas) | Tsau, Jyun-Syung (University of Kansas) | Nicoud, Brian (Chesapeake Energy) | Bradford, Kyle (Chesapeake Energy) | Baldwin, Amanda (Chesapeake Energy) | Mohrbacher, David (Chesapeake Energy)
Microscopic analysis including transmitted light, UV epifluorescence, BSE, and FIB-SEM carried out on Lower Eagle Ford (LEF) shale samples, selected from similar depths, show complex depositional fabrics, kerogen, migrated organic matter, and diagenetic history. It is well known that LEF samples contain depositional kerogen and migrated organic matter. Much of the migrated organic matter occupies diagenetically reduced primary porosity. Some of this organic matter is not porous, while some contains large pores and other contains a fine network of nanopores. Where thermal maturity is one control on porosity in organic matter, there is also a control of composition and origin. This paper investigates the chemistry of organic matter in-situ using Raman spectroscopy, to begin to understand what, other than thermal maturation, leads to porosity in both depositional kerogen and migrated organic matter. This is used to evaluate the nature of the pores in LEF, and to assess the impact of hydrocarbon gas injection on organic porosity.
Thin sections of the lower Eagle Ford shale samples are examined with transmitted light microscopy to select samples for Raman spectroscopy, after studying with FIB-SEM to analyze distribution of porosity in organic matter. In the Raman spectra, the separation between the D and G bands, the width of the G-band, and the intensity ratio of the D-to-G-bands are typically ascribed to maturity-related changes. However, composition and origin of the organic matter may also have an effect. The Raman spectra are analyzed to characterize the different types of porous and non-porous organic matter at the same depth. Then, samples are subjected to gas injection in the laboratory in preparation for a gas huff-n-puff operation, and changes in Raman spectra are analyzed once again.
BSE images show depositional kerogen is found as isolated bodies, lamellar forms, and fine material disseminated in the matrix. Transmitted light and UV microscopy reveal that some of this is non-fluorescent and some is fluorescent. Cement-reduced intraparticle pores, other primary pores, intercrystalline pores, and micro-fracture and micro-breccia pores contain migrated organic matter (OM), none of which fluorescences in UV. FIB-SEM images show the migrated OM has either spongy nanopores, larger bubble/meniscate pores, or no pores, all in the same sample. Raman spectroscopy analysis on the different types of organic matter show examples where both G- and D- bands are visible with distinctive separation, intensity ratio, or width, or where the D-band is absent. Moreover, the effect of gas injection on the different types of organic matter is inferred from the G- and D- bands.
This work improves our understanding of organic pore generation and modification, which influences pore size distribution and pore tortuosity, the underlying factors in gas huff-n-puff recovery in shales. It expands the utility of Raman micro-spectroscopy as a tool in understanding the evolution of pore systems and organic constituents in shale. It also presents an in-situ molecular structural study of the effect of hydrocarbon gas huff-n-puff on the different types of organic matter.
Constant confining pressure (CCP) tests and constant effective stress (CES) tests were widely conducted to measure shale permeability. The permeability data were explained by two types of permeability models, including apparent permeability models based on the slippage effects and poroelastic permeability models based on effective stress. In these experiments and models, the basic assumption is that the slippage effects, effective stresses and gas sorption-induced matrix swelling/shrinking are the reasons that cause shale permeability change, and they could be separated and investigated individually.
In order to see if this basic assumption was appropriate, we collected shale experimental permeability data measured under the CCP and CES conditions; as well as their comparison with solutions of the poroelastic theory and the apparent permeability theory, respectively. A conceptual model of shale permeability evolutions was built. It's found that for both CCP and CES tests permeability ratios are primarily determined by the transient effective stresses in shale with well-developed macro-fractures, or the slippage effects and the transient effective stresses in shale with less-developed macro-fractures. For shale samples with the effective flow radius of pores is smaller than 5μm (initial pore pressure=1.0MPa), the apparent permeability theory can be used to explain the permeability. The permeability ratio is bounded by an upper envelope which is corresponding to the combined solution of free-swelling and slippage effects (with the increase of pore pressure the k/k0 first<1 then rebound to >1 for CCP test, while for CES test the k/k0<1) and a lower one which is composed by zero-swelling and slippage effects (with the increase of pore pressure the k/k0<1 for both CCP & CES test). For shale samples with well-developed macro-fractures, the apparent permeability theory could not be used to explain the permeability data. Just like coal, the permeability ratio is also bounded by an upper envelope which is corresponding to the solution of free-swelling (with the increase of pore pressure the k/k0>1 for CCP test, while for CES test the k/k0=1) and a lower one which corresponds to zero-swelling (with the increase of pore pressure the k/k0<1 for both CCP & CES test).
Through these comparisons, we found that permeability data for both types of tests are confined within the solutions for two extreme boundary conditions: free-swelling for the upper bound, and zero-swelling and slippage effects combined for the lower bound. These findings suggest that permeability ratios for both CCP tests and CES tests are primarily determined by the matrix-fracture (or pores and dense matrix block) interactions, including sorption-induced swelling/shrinking, through transient effective stresses in matrixes and fractures (or pores and dense matrix block). This non-equilibrium seepage process is very important for shale gas extraction.