Christine Ehlig-Economides

A Triple-Continuum Pressure-Transient Model for a Naturally Fractured Vuggy Reservoir

We present an analytical approach for pressure transient test analysis in naturally fractured vuggy reservoirs. This analysis approach relies on a triple-continuum concept, using observed geological data from carbonate oil formations in western China, to describe transient flow behavior in fracturevug-matrix reservoirs. In the conceptual mathematical model, fractured vuggy rock is considered as a triple-continuum medium, consisting of fractures, rock matrix, and vugs (or cavities). Similar to the classical double-porosity model, the fracture continuum is assumed to be responsible for the occurrence of global flow, while vuggy and matrix continua (providing primary storage space) interact locally with each other as well as with globally connected fractures. Furthermore, the triple continua of fractures, matrix, and vugs are assumed to have uniform and homogeneous properties throughout, and intercontinuum flows between them are at pseudosteady state. With these assumptions, we derive analytical solutions in Laplace space for transient flow toward a well in an infinite and finite reservoir with wellbore storage and skin effects. The analytical solutions reveal typical pressure responses in a fracture-vug-matrix reservoir and can be used for estimating vug properties, in addition to fracture and matrix parameters, through properly designed and conducted well tests. As application examples, actual well test data from a fractured-vuggy reservoir in Western China are analyzed using the triple continuum model.

Pressure Transient Analysis in an Elongated Linear Flow System

The prominent examples of linear flow behavior in the well test literature relate to linear flow within or to a fracture penetrated by a producing well. The resulting pressure transients generally are exhibited in the early portion of a well test and are followed by infinite-acting radial flow behavior and/or boundary effects. In this paper, the linear flow occurs in the formation, which has a predominantly linear shape. Analysis of interference, drawdown, and build up tests is described in theory and illustrated by practical examples. The necessary equations for the analysis are provided for testing gas, geothermal steam, and oil wells. In elongated linear flow systems, the pressure transient behavior associated with linear flow occurs late in the drawdown or build up test. The type curves provided in this work show that this pressure behavior is readily distinguishable from conventional well tests, particularly in interference tests.

Numerical simulation of diverse thermal in situ upgrading processes for the hydrocarbon production from kerogen in oil shale reservoirs

We investigate the productivity and product selectivity of diverse thermal in situ upgrading processes in oil shale reservoirs. In situ upgrading processes applying the ideas of Shell In situ Conversion Process, ExxonMobil Electrofrac, and Texas A&M Steamfrac are simulated by using sector models with the assumption of symmetric patterns. In-house fully functional simulator is used, which has been developed for the kerogen pyrolysis and hydrocarbon production. In the simulation cases, sensitivity analyses to the factors having major influence on the productivity and product selectivity are conducted. The effects of the temperature of vertical heaters, the spacing of hydraulic fractures, and the position of horizontal production wells are analyzed in the applied In situ Conversion Process, Electrofrac, and Steamfrac, respectively. In the applied In situ Conversion Process cases, hydrocarbon production increases with the increasing heater temperature. In the applied Electrofrac cases, hydrocarbon production increases with the increasing spacing of hydraulic fractures, even though longer time period for the process is needed. In the applied Steamfrac cases, the case of production well located at the same depth to the injection well shows the least hydrocarbon production. Among the processes, the applied In situ Conversion Process cases show the highest weight percentage of total hydrocarbon components in the produced fluid, and the applied Electrofrac cases follow it. The applied Steamfrac cases show far lower weight percentage of hydrocarbon production than the other methods. In terms of the mass ratio of produced hydrocarbon to decomposed kerogen, the applied Steamfrac cases show the largest value among the processes by aqueous phase sweeping liquid organic phase, but they also show the huge water oil mass ratio by the continuous injection of hot water. All the applied In situ Conversion Process cases and the Electrofrac case with the short spacing of hydraulic fractures show good heating efficiency by decomposing whole kerogen in the system.

Compositional simulation of hydrocarbon recovery from oil shale reservoirs with diverse initial saturations of fluid phases by various thermal processes

We have studied the hydrocarbon production from oil shale reservoirs filled with diverse initial saturations of fluid phases by implementing numerical simulations of various thermal in-situ upgrading processes. We use our in-house fully functional, fully implicit, and non-isothermal simulator, which describes the in-situ upgrading processes and hydrocarbon recovery by multiphase-multicomponent systems. We have conducted two sets of simulation cases—five-spot well pattern problems and Shell In-situ Conversion Process (ICP) problems. In the five-spot well pattern problems, we have analyzed the effects of initial fluid phase that fills the single-phase reservoir and thermal processes by four cases—electrical heating in the single-phase-aqueous reservoir, electrical heating in the single-phase-gaseous reservoir, hot water injection in the single-phase-aqueous reservoir, and hot CO2 injection in the single-phase-gaseous reservoir. In the ICP problems, we have analyzed the effects of initial saturations of fluid phases that fill two-phase-aqueous-and-gaseous reservoir by three cases—initial aqueous phase saturations of 0.16, 0.44, and 0.72. Through the simulation cases, system response and production behavior including temperature profile, kerogen fraction profile, evolution of effective porosity and absolute permeability, phase production, and product selectivity are analyzed. In the five-spot well pattern problems, it is found that the hot water injection in the aqueous phase reservoir shows the highest total hydrocarbon production, but also shows the highest water-oil-mass-ratio. Productions of phases and components show very different behavior in the cases of electrical heating in the aqueous phase reservoir and the gaseous phase reservoir. In the ICP problems, it is found that the speed of kerogen decomposition is almost identical in the cases, but the production behavior of phases and components is very different. It is found that more liquid organic phase has been produced in the case with the higher initial saturation of aqueous phase by the less production of gaseous phase.

Comprehensive Model for Flow Behavior of High-Performance-Fracture Completions

This paper (SPE 124431) was accepted for presentation at the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, USA, 4–7 October 2009, and revised for publication. Original manuscript received 31 July 2009. Revised manuscript received 22 April 2010. Paper peer approved 28 June 10. Summary Experience shows that high-performance fractures (HPFs) may retain near-unit-flow efficiency (equivalent to zero skin in a vertical well) and rarely fail, even in highly deviated wells. This may be partly because overly simplistic models of the well flow behavior lead operators to maintain wells at lower production rates than could have been achieved for the same amount of injected proppant with a vertical-well-completion design. Rigorous models that account for widely accepted rock-mechanics fundamentals indicate that the fracture-to-well connection is compromised in deviated wells and lead to questions concerning whether the bulk of the flow to the well actually passes through the fracture. Distributed volumetric sources are used in this model to rigorously model a wide variety of possible fracture geometries such as an expanded wellbore because of halo effect, flow strictly through the fracture, and combined flow through a single fracture and to remaining flowing perforations not connected to the fracture. The model also includes turbulent-flow effects that may occur for radial-flow conditions in the fracture plane or in the reservoir opposite wellbore sections not connected to the fracture, along with high-velocity flow through the perforation tunnels. It also computes the effective flow area at the resulting face between the reservoir and the completion to check whether flow velocity exceeds conditions that would risk production of reservoir fines, and it estimates the screen-flow velocity on the basis of the number of flowing perforations. This comprehensive view of the HPF completion enables a thorough analysis of the risks of flowing the well at high rate. Field examples show that the new model depicts real field conditions in calculating the total skin, flow fractions, and the flux for HPF completions in high-rate gas and oil wells. Complete inflow-performance behavior for likely flow patterns for HPF wells in oil and gas reservoirs is provided.

Pressure Transient and Production Data Analysis for Hydraulic Fracture Treatment Evaluation

The Unified Fracture Design (UFD) concept provides a mechanism to determine the optimal hydraulic fracture design for a given amount of a selected proppant, while modern hydraulic fracture treatment execution offers the potential to achieve the optimal design. The proppant number is a ratio of the proppant permeability and proppant volume product to the formation permeability and reservoir volume product. The cost of the hydraulic fracture treatment is directly related to quality and quantity of proppant injected, and successful achievement of the optimal fracture treatment easily offsets this cost when appropriate economics is considered in the job design. Pressure transient and production data analysis are described in terms of fracture length and conductivity and do not provide measures of UFD parameters. The subject of this paper is the use of post treatment analysis to evaluate the effectiveness of the treatment in terms of dimensionless productivity index, dimensionless fracture conductivity, and the proppant number. Results of this analysis show that when conventional buildup tests cannot provide the desired post-treatment analysis, in most cases, production data analysis can, and vice versa. The analysis will address both single phase oil and gas primary production and oil production under pressure maintenance or waterflood. Also, non-ideal fractures with height growth beyond the producing formation thickness and fracture skin will be considered. Field examples will illustrate the analysis. The importance of this analysis is paramount for operators trying to optimize high value hydraulic fracture treatments.

Prediction of Fracture Initiation Pressure and Fracture Geometries in Elastic Isotropic and Anisotropic Formations

Laminated formation structures in shale formations may have elastic anisotropic properties, including Young’s modulus and Poisson’s ratio, that impact hydraulic fracturing treatment execution. Fracture initiation pressures and geometries are affected by these properties, especially in cased and in perforated horizontal wells. After initiation, stress concentration around the wellbore may cause the creation of longitudinal fractures (LFs) in the near-wellbore zone that reorient to transverse fractures (TFs) beyond this region. In this case, severe fracture kinking may occur that may hinder the transport of proppants and reduce well productivity. We developed an analytical model based on linear fracture mechanics theory to study the effect of perforation geometries on the initiation fracture pattern. Elastic anisotropy and well deviations were incorporated into simulations. Our simulation results show that when the perforation depth is in a specific range under normal fault regime, the initiation pressures for LFs can be smaller than the maximum horizontal stress

In situ upgrading of oil shale by Steamfrac in multistage transverse fractured horizontal well system

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