Fekete Associates Inc

Calgary, Canada

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Calgary, Canada
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Clarkson C.R.,University of Calgary | Rahmanian M.,Fekete Associates Inc | Kantzas A.,University of Calgary | Morad K.,Fekete Associates Inc
International Journal of Coal Geology | Year: 2011

Relative permeability to gas and water for 2-phase flow coalbed methane (CBM) reservoirs has long been known to exhibit a strong control on (gas and water) production profile characteristics. Despite its important control on both primary and enhanced recovery of CBM for coal seams that have not been fully dewatered, relative permeability in coal has received little attention in the literature in the past decade. There are few published laboratory-derived curves; these studies and their resulting data represent a small subset of the commercial CBM reservoirs and do not allow for a systematic investigation of the physical controls on relative permeability curve shape. Other methods for estimation of relative permeability curves include derivation from simulation history-matching, and production data analysis. Both of these methods will yield pseudo-relative permeability curves whose shapes could be affected by several dynamic CBM reservoir and operating characteristics.The purpose of the current work is to perform a systematic investigation of the controls on CBM relative permeability curve shape, including non-static fracture permeability and porosity, multi-layer effects and transient flow. To derive the relative permeability curves, effective permeability to gas and water are obtained from flow equations, flow rates and pressure data. Simulated cases are analyzed so that derived and input curves may be compared allowing for investigation of CBM reservoir properties on curve shape. One set of relative permeability curves that were input into the simulator were obtained from pore-scale modeling. Field cases from two basins are also examined and controls on derived relative permeability curve shape inferred. The results of this work should be useful for future CBM development and greenhouse gas sequestration studies, and it is hoped that it will spark additional research of this critical CBM flow property. © 2011 Elsevier B.V.


In the first part of this paper, the pressure and temperature measurements obtained using Schlumberger's Modular Formation Dynamics Tester (MDT) conducted on the C2 interval in the BPXA-DOE-USGS Mount Elbert Gas Hydrate Stratigraphic Test Well (Mount Elbert Well) are history matched, with the following three objectives: (i) to obtain a better understanding of hydrate decomposition and its reformation as conditions cross the p/. T stability, (ii) to obtain formation properties (e.g., permeability) that are consistent with the measurements, and (iii) to explore the non-uniqueness in the history match; i.e., to explore the ranges of parameters that allow a reasonable match of the measured quantities. In the second part of this paper, long-term production performance is predicted, and the effect of the uncertain parameters on the predictions is demonstrated. The results are used to demonstrate the range of long-term production that may be expected, when a model is calibrated using the MDT data. Usefulness of short-term tests for long-term forecast prediction is then discussed. © 2010 Elsevier Ltd.


Moghadam S.,Fekete Associates Inc | Jeje O.,Fekete Associates Inc | Mattar L.,Fekete Associates Inc
Journal of Canadian Petroleum Technology | Year: 2011

Material balance has long been used in reservoir engineering practice as a simple yet powerful tool to determine the original gas in place (G). The conventional format of the gas material balance equation is the simple straight line plot of p/Z vs. cumulative gas production (GL), which can be extrapolated to zero p/Z to obtain G. The graphical simplicity of this method makes it popular. The method was developed for a "volumetric" gas reservoir. It assumes a constant pore volume (PV) of gas and accounts for the energy of gas expansion, but it ignores other sources of energy, such as the effects of formation compressibility, residual fluids expansion and aquifer support. It also does not include other sources of gas storage, such as connected reservoirs or adsorption in coal/shale. In the past, researchers have introduced modified gas material balance equations to account for these other sources of energy. However, the simplicity of the p/Z straight line is lost in the resulting complexity of these equations. In this paper, a new format of the gas material balance equation is presented, which recaptures the simplicity of the straight line while accounting for all the drive mechanisms. This new method uses a p/Z** instead of p/Z. The effect of each of the previously mentioned drive mechanisms appears as an effective compressibility term in the new gas material balance equation. Also, the physical meaning of the effective compressibilities are explained and compared with the concept of drive indices. Furthermore, the gas material balance is used to derive a generalized rigorous total compressibility in the presence of all the previously mentioned drive mechanisms, which is important in calculating the pseudotime used in rate transient analysis of production data.


Reza Etminan S.,University of Calgary | Pooladi-Darvish M.,University of Calgary | Pooladi-Darvish M.,Fekete Associates Inc | Maini B.B.,University of Calgary | Chen Z.,University of Calgary
Fuel | Year: 2013

Measurement of gas diffusivity in reservoir fluids is of great interest for a number of applications, and among different methods for the measurement, the Pressure Decay method has received special attention due to its simplicity. In this technique, a non-volatile quiescent oil column is brought in contact with a diffusing single component gas from the top and the rate of change of gas pressure in the gas cap is recorded. The interpretation of outcomes is based on solution of a forward problem, which sometimes invokes a complicated boundary condition. In this work, an analytical solution is presented for the most general form of the boundary condition which models the interface. It takes into account all mass transfer key parameters including gas solubility, a diffusion coefficient and a possible interfacial resistance. The effect of resistance against mass diffusion at the interface is usually neglected in modeling. Through this solution, the role of interface resistance is better explained and one can realize how the resistance exactly affects the diffusion process. A detailed sensitivity analysis of each parameter is conducted and specifically in the case of interface resistance, it is illustrated that a numerical value can be reported for the interfacial resistance while it does not affect or hinder the diffusion process physically. This could unnecessarily increase the degree of freedom of the backward problem, and may lead to misleading parameter estimation results (despite a good match of the measurements). Using our new interface boundary condition reveals that some of the previous works on the modeling of interface resistance are subject to underestimation of the rate of gas dissolution which may lead to erroneous estimation of parameters. © 2012 Elsevier Ltd. All rights reserved.


Zeidouni M.,University of Calgary | Pooladi-Darvish M.,Fekete Associates Inc
Journal of Petroleum Science and Engineering | Year: 2012

Deep saline aquifers are widely used for waste disposal and are the main candidates for storage of CO2 as a means of reducing greenhouse gas emissions to the atmosphere. Safety of disposal/storage projects highly depends on the containment of CO2 within the target aquifer. However, since the cap-rock overlying the aquifer may include leakage pathways that permit the injected fluids to leak to subsurface formations and/or to surface, detection and characterization of any such pathways from storage formations into overlying formations are required. A leakage test has been introduced in an earlier paper to characterize a leakage pathway through pressure monitoring in an overlying aquifer separated from the target aquifer by the cap-rock. A leakage pathway can be characterized by the leak transmissibility and location parameters, so a successful test should be able to provide sufficient confidence to evaluate the transmissibility and location parameters. In this work, different strategies are evaluated in order to achieve a successful test. The strategies include increasing the sampling frequency, use of pulsing, and increasing the number of monitoring/injection wells. The information provided by different strategies is evaluated, based on their effects on well-posing the inverse problem. The effects are studied based on information and correlation matrices, as well as the confidence interval. Locating the monitoring well is studied considering the requirements to ensure the safety of CO2 storage projects. Finally, we present a graphical method to obtain prior information on the leak based on the pressure derivative data. The graphical method is obtained based on deriving a new real-time analytical solution for the pressure at the monitoring zone. © 2012 Elsevier B.V.


Pooladi-Darvish M.,Fekete Associates Inc | Pooladi-Darvish M.,University of Calgary | Moghdam S.,Fekete Associates Inc | Xu D.,Fekete Associates Inc
Energy Procedia | Year: 2011

Geological storage of CO2 in deep saline aquifers has been suggested as a potential methodology for reducing CO2 emissions over short to medium terms. A number of projects are in operation and a larger number are being designed. However, not all aquifers are equally suitable for CO 2 storage. Virtually all publications that present the criteria for selection of suitable sites for geological storage of CO2 in aquifers, consider injectivity to be among the top three criteria, with capacity and containment being the other two. Among parameters that affect injectivity, permeability can vary by the largest degree. Unfortunately, selection of storage sites with sufficient permeability that would enable injection of the desired volumes, using only one injection well - such as that achieved in Sleipner - is not always possible. When this is not possible, injectivity needs to be improved for example by increasing the contact area with the formation (e.g. through application of hydraulic fracturing or horizontal wells) and/or employing more than one injector. Recent studies indicate that multiwell injectivity does not increase linearly with the number of injectors. Instead, progressively more number of wells is required to achieve an equal increment in injection rate. It is well known, that because of the small compressibility of the water, it takes a short time for the pressure pulse from the different injectors to cause significant interference. We use this observation and suggest a well pattern that would minimize such interference effects in an open and homogeneous aquifer. Next, we develop an analytical solution, for the injectivity of multiwell systems as a function of (i) number of wells, (ii) distance between wells, and (iii) injectivity of one wel.. The analytical solution obtained for single-phase flow is applied to cases of CO2 injection in aquifers. Numerical experimentation over a wide range of parameters demonstrates the applicability of the analytical solution for two-phase flow problems. This relation is developed for homogeneous aquifers; suggesting that such a relationship may be used for scoping and screening studies early on when data us scarce, and the effect of the number of wells and/or their distance on overall injectivity is being studied. Furthermore, such a relationship allows examining the economic balance between increasing the number of wells or the distance among wells. © 2011 Published by Elsevier Ltd.


Zeidouni M.,University of Calgary | Pooladi-Darvish M.,Fekete Associates Inc
Journal of Petroleum Science and Engineering | Year: 2012

Deep saline aquifers can provide the capacity for disposal/storage of undesirable surface fluids. To maintain containment and thereby prevent leakage of the injected fluids, the target aquifer should be overlain by a confining layer (cap-rock). However, there may be pathways in the cap-rock (e.g., transmissive faults, abandoned wells, active wells that partially penetrate the seal, and local seal weaknesses and fractures) that permit leakage of the injected fluids. Leakage to the subsurface formations may adversely affect the existing and potential energy and mineral resources and shallow ground water resources and soils. As such, detection and characterization of leakage pathways from storage formations into overlying formations are required. In this work, we suggest a flow and pressure test and present an inverse methodology to detect and characterize radially shaped leakage pathways based on the pressure data. The flow test is based on the injection (or production) of water into (or from) a target aquifer at a constant rate. The pressure is measured at a monitoring well in an aquifer overlying the target aquifer, which is separated by a cap-rock. Characterizing the leak based on pressure data involves solution of the leakage inverse problem. We investigate the uniqueness of the solution to the inverse problem through the use of the Hessian matrix and an analytical approach. The stability of the solution is analyzed based on sensitivity coefficients and the correlation matrix. The analyses are applied to a base case problem for which the leak characteristics are obtained over a confidence interval. © 2012 Elsevier B.V.


Morad K.,Fekete Associates Inc | Morad K.,Royal Dutch Shell
Journal of Natural Gas Science and Engineering | Year: 2012

Natural gas production from coalbed methane reservoirs makes up a sizable portion of total natural gas production in North America. In other countries such as Australia, China, Russia, UK, to name a few, coalbed methane is receiving a lot of attention and coalbed methane producers are keen to learn from North American experience in screening, exploration, pilot testing appraisal and field development.In this review, a select number of subjects important in describing the behavior of a coalbed methane reservoir and in predicting its future productivity, are reviewed. © 2011 Elsevier B.V..


Trademark
Fekete Associates Inc | Date: 2011-03-01

Computer software for the acquisition and calculation of natural gas and petroleum data.


Trademark
Fekete Associates Inc | Date: 2012-12-11

Printed answer sheets in the field of organizational psychology; Printed pamphlets, brochures, manuals, books, booklets, leaflets, flyers, informational sheets and newsletters, adhesive backed stickers, and kits comprising one or more of the foregoing materials in the field of organizational psychology.

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