Reservoir characterization in unconventional reservoirs can be problematic due to the magnitude of uncertainties in the measurements being made. While significant advances continue to be made in logging tool capabilities and the integration of detailed core and petrophysical analyses, the utilization of these results on a routine basis for reservoir characterization during development horizontal drilling is cost prohibitive. Additionally, time delays in obtaining results from core analysis make this approach inappropriate for operational situations.
A method by which detailed reservoir characterization can be undertaken in a cost-effective and timely manner is required.
This paper describes the results from the trial testing of the geological differential method (GDM). The trial uses routine drilling parameters, mud gas data, lithology data and associated core calibrated petrophysical analyses from multiple (model) wells to determine routine petrophysical properties such as porosity and fluid/gas volumes in unknown (prediction) wells. This new technique is fundamentally different from existing neural networks and other statistical based systems. Rather than using the input data to provide a basis for informed inference or extrapolation, it is used as part of a predictive process. This paper summarizes the work flows and results of three separate projects involving nine lower Paleozoic exploration wells and a variety of unconventional targets. We describe the work flows in general and show comparisons between reservoir characteristics determined by routine petrophysical analysis and predictions using the GDM for three separate blind tests.
Testing has successfully shown that we were able to relatively quickly (within 2-3 weeks) develop a predictive model, which could, within reason, predict basic reservoir characteristics for tight gas sands from routine drilling parameters, mud gas and lithology data. While further input data preparation is required, initial results provided significant encouragement and highlighted the potential of this technique for both real-time and post-drilling analysis.
Organic-rich shale gas reservoirs have various complexities related to the physics of gas storage and transport. Traditionally, the OGIP in shales is calculated by the sum of the adsorbed-gas and the free-gas, as an analog of the CBM reservoirs. However, as noted by a few authors, the free-gas volume must be corrected for presence of adsorbed-gas, assuming all gas storage occurs in kerogen. Even with such correction, shales are still complex reservoirs in terms of flow characteristics. The contribution of viscous, diffusive, and slip forces in nano-scale conduits cause the permeability to be higher than its value expected by Darcy’s law.
A new model is developed to address the effect of the adsorbed-gas volume on the micropore storage capacity. The relative fraction of adsorbed-gas volume is treated as sorbed-phase saturation. The initial free-gas volume is then calculated by subtracting any non-free-gas saturation from the effective void volume. We have extended this concept to a gas material balance equation through which the free-gas volume is dynamically adjusted during depletion. The SLD adsorption model is used to evaluate sorbed-phase density and volume. To address the complexity in gas flow, permeability of the reservoir model is a function of pressure to determine the impact of advection, slippage and diffusion mechanisms. The permeability is calculated via a multi-mechanism flow model. Finally, we utilized the dynamically-corrected permeability in parallel with dynamically-corrected porosity to simulate the primary recovery of a shale gas reservoir.
The new models successfully describe the unique characteristics of shale reservoirs and correct the conventional methods for overestimation of reserves and underestimation of permeability. The format of the final material balance equation and the flow model used here keep the conventional reservoir engineering framework, which are familiar to the
engineers, but with some modifications.
Microseismic data was acquired with a permanently installed shallow buried array of geophones during the hydraulic fracturing of 17 wells in the Marcellus Shale. The processed results were used to conduct a multi-disciplinary study integrating geology, geomechanics, reservoir and completion engineering, and ultimately, production data. A stress inversion from focal mechanisms was performed, and correlations were made between hydrocarbon production and microseismic results. That work, in conjunction with the variability in the stimulation approach, was used to optimize the treatment design on an individual wellbore and on a field development scale. Incorporating information from source mechanisms, an event magnitude calibrated discrete fracture network (DFN) was designed taking into account the seismic energy of the events, rock properties, the injected fluid volume as well as fluid efficiency. Evaluating the placement of proppant inside the DFN allowed for discerning between the part of the stimulated rock volume (SRV) that contributes to production in the long term, and the part of the reservoir that was affected by the treatment but may not be hydraulically connected over a longer period of time. Finally, the permeability of the stimulated fracture system was calculated from the microseismic results. This allowed for the evaluation of the drainage volume and estimation of production.
Seismic forward modeling is an integral component of microseismic location algorithms. There is generally no one correct approach, but rather a range of acceptable approaches that can be used. For instance, if first-order effects of material averaging (or wavelength smoothing) can be modelled by a gradually varying medium and the wave path lengths are not too great, then basic ray methods should be applicable. On the other hand, if strong multiple scattering and/or wide-angle diffraction is important, a numerical solution of the full anisotropic elastic wave equation is necessary. Thus, selecting an appropriate method involves weighing the advantages and disadvantages of all acceptable approaches in terms of accuracy requirements and computational limitations. Since microseismic signals are band limited, the length scale of heterogeneities can significantly influence the seismic wavefronts and waveforms. This can be especially important when subsurface heterogeneity is strong and vary on scales lengths equivalent of less than the dominant source wavelength (as is the case for many unconventional reservoirs). Are ray-based approaches suitable for microseismic applications? We argue that for advanced imaging techniques, ray based algorithms may not be suitably accurate. In this paper, we focus on exploring the feasibility of using one-way wave equations as Green functions for “full waveform” location techniques. One-way wave equations are capable of modelling the evolution of important and observable wave phenomena across an array and could represent a class of efficient full waveform modeling tools. As a feasibility study, we focus on the acoustic wave equation to explore efficiencies and compare travel-time and amplitude errors. However, the results have implications for one-way wave equations for elastic and anisotropic media.
Effective asset life cycle water management is key to the technical and economic success of both unconventional gas and conventional oil developments. Unconventional gas resource development in densely populated Europe presents different frac water management challenges to those in sparsely populated areas of the USA. How can decades of worldwide experience of onshore conventional oil produced water management be applied to improve water management for unconventional gas wells in the areas of: - Sourcing frac water supplies - Obtaining permits for water abstraction and disposal - Resolving stake holder environmental concerns - Investigating frac water related formation damage - Understanding returned frac water composition - Treating and recycling frac water - Minimizing frac water requirements Onshore water management for unconventional gas and conventional oil production are compared and contrasted with the objective of optimizing frac water life cycle management for unconventional gas resources in Europe.
Hendraningrat, Luky (Norwegian University of Science and Technology (NTNU)) | Souraki, Yaser (Norwegian University of Science and Technology (NTNU)) | Torsater, Ole (Norwegian University of Science and Technology (NTNU))
Most of current total world oil resources are coming from unconventional oil such as heavy oil, extra heavy oil and bitumen. Since conventional light crude oil production is declining and its resources has short fall, those unconventional oil are increasingly interesting in recent years. However the most difficulty to handle those oils is their high viscosity. Thermal application methods constitute great importance for heavy oil production. The development of current technology has enabled manufacturer to create various types of nanoparticles, including metal nanoparticles, for multi-purposes in various sectors including the oil and gas industry.
The metal nanoparticles-assisted heavy oil production seems potentially interesting as catalyst to increase efficiency of heat transfer mechanism. The purpose of study is to investigate the effect of using metal nanoparticles for viscosity reduction of heavy oil. In-situ thermal induction and aquathermolysis methods are conducted.
In this study, various metal nanoparticles compound with different thermal conductivity: Cu, Zn, Ni and Fe, are employed and Athabasca bitumen was used. Those nanoparticles are characterized under scanning electron microscope and their compounds are identified by energy-dispersive X-ray spectroscopy (EDX) analysis. The Athabasca bitumen is blended with metal-nanoparticles using sonicator at given concentration. Water is used for aquathermolysis method. Both methods are conducted in various temperatures. Those methods are then compared to identify their efficiency. Metal nanoparticles type and size are also involved in this study. There are momentous changes in heavy oil viscosities by using those catalysts.
The detailed process and results are outlined in the paper to reveal the possible application of metal nanoparticles to assist heavy oil recovery.
In the Vaca Muerta shale located in the Neuquén basin, Argentina, the most prolific intervals tends to be the most difficult to hydraulically fracture due to the abnormally high fracture gradients present in some parts of the basin. Thus it becomes very important to have a good understanding of the anisotropic geomechanical properties of this heterogeneous formation prior to developing the completion strategy.
This paper presents a case history where a calibrated, anisotropic 1D mechanical earth model (1D MEM) was developed and used in developing an optimized completion strategy for a vertical well in the Vaca Muerta shale. The output from the 1D MEM including the principal stresses, anisotropic elastic properties, pore pressure and rock strength, were used to define the reservoir intervals with best characteristics for initiation, propagation and maintenance of a conductive complex fracture network. Next, the reservoir intervals with the highest hydrocarbon generation tendency were determined from petrophysical and image logs acquired on the well. This formed the basis for selecting the optimum number of stages and perforation strategy on the well.
Sensitivity analysis revealed the impact of the hydraulic fracture properties on the production performance, e.g. higher fracture conductivity greatly improves the well performance in the deeper Vaca Muerta intervals, while larger fracture surface area is more beneficial across the shallower intervals. Thus, a unique completion strategy was developed for each interval to optimize the well performance. Three hydraulic fracture stages were eventually planned, but due to casing limitation, only the first stage was eventually executed. A time-lapse acoustic measurement acquired on the well corroborated the propped fracture height predicted during the completion design phase.
This example illustrates how proper characterization of the anisotropic geomechanical behavior of the Vaca Muerta formation improves the development of a completion strategy which ultimately optimizes economic performance of the well.
Gas hydrates will dissociate to gas and water provided the prevailing pressure is below the equilibrium pressure or the prevailing temperature is above the reservoir equilibrium temperature. Moreover, some hydrate reservoirs have considerable amounts of mobile gas and water coexisting with the hydrates in the formation. This implies, fluid diffusivity in such a reservoir system is predominantly multiphase and hence addressing multiphase flow for well testing in such reservoirs becomes very vital.
Conventionally, most well testing models address diffusivity in porous media by assuming a single/dominant flowing phase or addressing the fluid phases separately. If a huge discrepancy exists between the fluid saturations, the fluid with the highest saturation denotes the dominant flowing phase and the correction with the multiphase model becomes trivial, as also seen with most conventional gas reservoirs with low water saturation, illustrated similarly in this work. However, if the saturations of the different phases do not vastly differ from one another, multiphase well testing models give a more accurate prediction of reservoir behavior. The use of total mobility and total compressibility concepts become very essential in deriving a better estimate of the diffusivity of the fluids and for well test designs.
The multiphase flow model developed here is based on a mass balance system. The effective density, total compressibility and total mobility are derived from a mass balance model. The total mobility model developed by Perrine, used by most reservoir engineering calculations is not considered for this work, as this does not fulfill mass balance. Due to the non-linearity of the diffusivity equation, the multiphase diffusivity model addressed here includes pseudo-pressure integrals. The solutions to the multiphase model are compared to single phase well testing models with saturation sensitivity studies and the limitation of using the single phase models are highlighted.
For the development of unconventional resources enormous efforts are required. All the necessary operations cause short-term as well as long-term impacts on the environment and on the social life.
In order to study those potential impacts and to find measures to keep them as low as possible, modeling contributes significantly to this goal.
The herein described model is a fully integrated model that comprises every key component for such a development between the geological extent of the shale formations up to the pipeline and distribution network.
Geology makes up the baseline for all calculations. However, especially in Central Europe, many areas on the surface are restricted, or even inaccessible due to various regulations. All necessary operations have to fit within these given subsurface and surface boundary conditions as well as the regulatory framework. Well designs, stimulation treatment designs and the resulting logistics form a complex mathematical network and multidimensional analysis is required in order to find development options that meet the environmental standards, by still allowing companies to be economical.
The combination of all those various kinds of disciplines is a highly complex task and hybrid modeling techniques are required to systematically approach such a problem. System dynamics modeling in combination with Agent Based Modeling and GIS data allows to study tasks as the relative increase of truck transportation in a specific area when loading the model with actual Central European traffic data. Further, the model shows the implication on various concerns as water consumption or land use and surface footprint. Using proper visualization techniques, the model presents a means of communication to the stakeholders. The industry’s efforts on minimizing the effect of a development on social life and the environment can herewith be described in an effective and scientific way.
Successful United States shale plays are often used as a template for the drilling and completion strategies for newly emerging shale plays around the world. However, studies of production logs in the Barnett Shale (SPE 144326), the Marcellus Shale and the Eagle Ford Shale have shown that a significant percentage of perforations clusters are not producing quantifiable amounts of fluid or gas. Case studies designed to address this have shown that addressing the heterogeneity experienced around the wellbore (SPE 155485) in combination with more focus on landing and staying in the best quality reservoir rock (SPE 138427) lead to more productive wells with a higher degree of perforation performance.
The challenge faced by many operators is incorporating a completion optimization workflow into their completions that is both technically effective and cost effective. The desired completion system is one that incorporates as much information as needed for successful completion while being operationally unobtrusive. Refined techniques used to convey dipole sonic tools in cased laterals have been supplemented by a new generation of easily deployed tools capable of making density, neutron, resistivity, and sonic measurements in open hole. This gives operators a wide array of options that can fit into a completion optimization program.
This paper reviews the concept of optimized plug and perf completions as compared to the more frequently used approach of geometrically spacing stages and perforations. Reservoir quality and completion quality variables are discussed along with different types of data that can be easily acquired with cost effective methods and how those data can be used in completion optimization. Finally, a work flow that is repeatable, portable, and effective is introduced that can be applied to any rock type where variation in petrophysical or mechanical properties along lateral wells are expected.