Hydraulically-fractured vertical and horizontal wells completed in the tight formations typically exhibit long periods of transient linear flow that may last many years or decades. From this transient linear flow period, the linear flow parameter (xfk) may be extracted. However, changes in effective permeability to the oil phase during production, caused by wellbore pressure falling below the saturation pressure, affect the flow dynamics in tight oil reservoirs and complicate the analysis. The use of methods that assume single-phase flow properties, such as the square-root of time plot, can lead to significant errors in linear flow parameter estimates.
In this study, an analytical method is introduced to mathematically correct the slope of the squareroot- of-time plot for the effects of multi-phase flow through the use of modified pseudovariables. Although the correction was derived for wells producing at constant flowing pressure during transient linear flow, the method is extended for wells producing at variable rate/flowing pressures. In order to evaluate pseudovariables used in the correction, the saturation-pressure relationship must be known. In this work, an analytical method for evaluating the saturation-pressure relationship is also developed.
The results of our new analytical method for linear flow analysis are validated against numerical simulation. The new method yields linear flow parameter estimates that are within 10% of those input into the numerical simulator.
The rapid pace of exploitation of unconventional gas and light oil (UG/ULO) plays in North America has necessitated the development of new production forecasting methodologies to aid in reserves assessment, capital planning and field optimization. The generation of defendable forecasts is challenged not only by reservoir complexities but also by the use of multi-fractured horizontal wells (MFHWs) for development.
In this work, we have developed a semi-analytical method that provides a solid theoretical basis for forecasting. The technique is analytical in that it uses the methods of Agarwal (2010) to calculate contacted oil- and gas-in-place (COIP/CGIP) from production rates, flowing pressures and fluid properties. The rate-normalized pressure (for liquids) or pseudopressure (for gas) derivative (RNP’) is a key component of the calculation. The technique is also empirical in that an empirical function is fit to the resulting COIP/CGIP curve versus time. Although the method is flexible enough that any equation can be used to represent the COIP/CGIP curve, and hence the sequence of flow-regimes exhibited by MFHWs, the equation must be capable of being integrated to allow extraction of rate-normalized pressure or pseudopressure (RNP). The stabilized COIP/OGIP during boundary-dominated flow must be specified for forecasting – thereafter, the method uses a material balance simulator to model boundary-dominated flow. Hence, if the well is still in transient flow, a range in forecasts may be generated, depending on the assumed stabilized COIP/OGIP.
Our new semi-analytical method addresses some of the current limitations of empirical and fully analytical (modeling) approaches. Empirical methods, which have been adapted to account for long transient and transitional flow periods associated with ultra-low permeability reservoirs, lack a theoretical basis, and therefore input parameters may be difficult to constrain. However, empirical methods are simple to apply and require a minimum amount of data for forecasting. Analytical models, while better representing the physics, nonetheless require additional reservoir and hydraulic fracture data which may not be available on every well in the field. The semi-analytical method proposed herein is intended to bridge the gap between empirical and modeling-based approaches – it is more rigorous than purely empirical methods, while requiring less data than fully analytical techniques.
The new method is tested against simulated and field cases (tight oil and shale gas). Although we have used a simple power-law function to represent COIP/OGIP curve, which appears adequate for the cases studied, we note that wells exhibiting long transitional (e.g. elliptical/radial) will likely require a different functional form.
Unconventional gas reservoirs have complex storage and transport properties that are difficult to characterize and are dynamic. The large internal surface area of nano-scale organic pores gives them the capability to store adsorbed gas along with free gas, with the amount of free gas storage changing as a function of adsorption/desorption. Further, diffusion and slippage mechanisms compete with compression and possibly matrix shrinkage effects to alter absolute permeability of the organic matter pores. An additional factor controlling permeability change, which has not been previously considered, is the change of effective radius of organic matter pores as a function of adsorption/desorption. A statistical study is required to fully explore the overall effect of the above mentioned parameters on unconventional gas well production performance, along with other properties such as total carbon content, pore connectivity configuration, adsorption capacity, pore size distribution, and natural fracture intensity.
In this study we investigate two sets of matrix pore sizes thought to represent a reasonable range observed in unconventional gas reservoirs. Pore size affects the interaction between the gas molecules and pore walls and results in a distribution of adsorbed phase thickness. Therefore, the adsorbed layer modifies the effective hydraulic radius for flow of gas which in turn alters the effective permeability to the gas phase in organic matter pores. This complexity can be captured by combining the simplified local density model and apparent permeability approaches. The contribution of compression and matrix shrinkage to fracture permeability change with pressure is also investigated and compared to changes in apparent permeability in the matrix caused by diffusion and slippage mechanisms.
A commercial reservoir simulator is used to study the effects of pore size and pore size alteration, and consequent permeability changes, on unconventional gas well performance. A screening statistical method is used to quantify the relative importance of each factor.
The results of this study will help the engineers evaluate the relative importance of all of the permeability-altering processes that can affect unconventional gas well performance, and make appropriate simplifying assumptions. This will enable them to prioritize history matching parameters for real production data analyses and forecasting, which in turn decreases the time required for a complete field simulation study.
Organic-rich shale gas and CBM reservoirs have an ultra-fine matrix pore structure, often in the nanometer-scale, which imparts complex fluid storage and transport mechanisms. Both reservoir types are also often naturally-fractured, which has an important control on fluid transport.
Gas storage may occur through a variety of mechanisms including free gas within the matrix and fracture porosity, and adsorbed gas storage on the internal surface area of the organic matrix (Faraj et al., 2004; Hamblin, 2006; Bustin et al., 2008). Storage of gas in solution within pore fluids and within organic matter may also be important (Thararoop et al., 2012, Swami & Settari, 2012 respectively). The adsorbed gas fraction in shales and coals is variable, depending on organic matter content, type, thermal maturity and a variety of other factors (Drake, 2007). Gas adsorption often forms an adsorbed layer on the pore wall under typical reservoir conditions for coal and shale, and this adsorbed layer can affect the initial gas-in-place estimation and transport capacity of the pore conduits, especially when the size of pores is on the scale of nanometers.
As a result of low gas prices and recent reductions in natural gas liquids prices, unconventional light oil reservoirs remain a primary target for exploration and development in North America. Due to the low permeability of such reservoirs, well-life tends to be dominated by transient linear flow from the matrix to the fractures which may last several years. This flow period is affected by hydraulic fracture properties, therefore operators are looking for new methods to characterize hydraulic fractures, particularly early in the well life. In previous studies by the authors it has been shown that high-frequency flowback flow rates and flowing pressures can be modeled to obtain key hydraulic fracture parameters (i.e. half-length and conductivity). Although commingled data is commonly gathered, technology exists to collect individual stage data.
In this work, we advance the analytical procedure presented by Clarkson and Williams-Kovacs (2013b) and Williams-Kovacs and Clarkson (2013c) for analyzing pre- and post-breakthrough of formation fluid during flowback of light tight oil wells by investigating multi-well and stage-by-stage flowback. Studies have shown that there may be significant communication both between stages and between wells on a given pad (or beyond) during the flowback period but not during long-term production. In order to accurately model the flowback period this communication must be accounted for in order to properly assess individual well hydraulic fracture properties. Building upon the analytical models developed previously for single well flowback from unconventional light tight oil wells, we employ the “communicating tanks” concept to account for stage (or inter-well) interaction. Proper allocation and transfer of fluids between stages, if they are communicating, is necessary to ensure that the fracture volume assigned to each stage/well is correct. Our work demonstrates that if individual stage/well flowback data is analyzed without accounting for communication, derived reservoir properties (i.e. fracture half-length) are in significant error. As a result, future well performance predictions, and attempts to optimize fracture stimulations, will also be in error.
Our new methods are tested against both simulated and field examples. Stage-by-stage flowback is demonstrated using simulated data, while multi-well flowback will be demonstrated using field data from a multi-well pad.
Tight oil reservoirs are typically developed using multi-fractured horizontal wells (MFHWs) due to the low permeability of the rock matrix. A common challenge for these reservoir types is the timely and accurate characterization of hydraulic fractures; this characterization is important for accurate forecasting of well production and optimization of future development. Recently, operators have relied more on early-time fracture characterization methods, due to the significant time required to confidently extract fracture properties from on-line production data. Early-time characterization methods include: microseismic fracture mapping, hydraulic fracture modelling, short-term post-frac welltests and quantitative analysis of flowback data.
It is common practice to use PVT data measured in laboratories (i.e. bulk fluid properties) for reservoir modeling and production data analysis purposes. However, theoretical studies have shown that fluid properties (including critical properties, phase behavior, viscosity, density, etc.) change under nano-scale confinement in shale reservoirs due to the abundance of interactions between the fluid molecules and the pore walls (pore proximity effects). In addition to these effects, in nanopores, an adsorbed layer can form which could cause changes in the apparent permeability to the free gas phase. The purpose of this study therefore is to incorporate the effects of pore proximity and adsorbed layer thickness changes into rate-transient analysis. The transient linear flow period in particular is studied for this purpose as it is often the dominant flow period in shale gas wells.
An iterative integral method is used to solve the nonlinear partial differential equation (PDE) for fluid flow in the presence of pore proximity effects and changing adsorbed layer thickness. Fluid properties (i.e. viscosity and density) under confinement are simulated using critical property adjustments and conventional fluid property correlations. The simplified local density model is used to estimate the thickness of the adsorbed layer, and this is coupled with an apparent permeability equation, which accounts for diffusion and slippage phenomena, to quantify permeability alteration in the presence of an adsorbed layer. Stress-sensitivity of permeability is also accounted for.
The results of our analysis using simulated data show that neglecting proximity effects in linear flow analysis leads to overestimation of the linear flow parameter (i.e. xf√ki) in nanoporous shale reservoirs. This in turn could cause errors in the derivation of fracture half-length, if permeability is known, or vice-versa.
The new modified analytical rate-transient analysis tools and procedures provided in this work will lead to improved linear flow analysis, should pore proximity and confinement effects be important. In general, this method can be used for inclusion of different pressure-dependent fluid and rock properties and processes in the analysis of shale gas reservoirs.
Transient linear flow is often the dominant flow regime in multi-fractured horizontal wells, and is characterized by a straight line on a square-root-time plot, which is a plot of rate-normalized pseudopressure (for gas reservoirs) or rate-normalized pressure (for oil reservoirs) against square-root of time (Wattenbarger et al. 1998). Square-root-time plots are used to estimate fracture half-length provided that an estimation of the initial formation permeability is given. The slope of the pseudopressure-based square-root-time plot (used for gas reservoirs) overestimates fracture half-length, whereas the pressure-based version (used for oil reservoirs) underestimates fracture half-length. Therefore, the slope of the square-root-time plot needs to be corrected for high drawdown (Ibrahim and Wattenbarger 2006; Nobakht and Clarkson 2012a,b), stress-sensitivity of permeability (Qanbari and Clarkson 2013a,b), and multi-phase flow (Qanbari and Clarkson 2013c) using a correction factor; pseudopressure should also be used for oil reservoirs before calculating the correction factor. The combination of pseudopressure and correction factor accounts for the impact of pressure-dependent rock and fluid properties and multi-phase flow on the slope of square-root-time plot and consequently improves the accuracy of the calculated fracture half-length.
Clarkson, Christopher R (University of Calgary) | Williams-Kovacs, Jesse (University of Calgary) | Qanbari, Farhad (University of Calgary) | Behmanesh, Hamid (University of Calgary) | Heidari Sureshjani, M. (IOR Research Institute)
Copyright 20 14, Society of Petroleum Engineers This paper was prepar ed for presentation at the SPE/CSUR Unconventional Resources Conference -- Canada held in Calgary, Albe rta, Canada, 30 September - 2 October 2014 . This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract mus t contain conspicuous ac knowledgment of SPE copyright.
Although matrix permeability is an important control on the commercial viability of unconventional reservoirs, there is no consensus on the appropriate way to measure it in the lab. In previous work (Clarkson et al. 2012), we investigated the use of pressure- and rate-transient analysis (PTA/RTA) methods to analyze data obtained from a new core plug analysis procedure designed specifically to extract information (permeability and pore volume) from ultra-low permeability reservoir samples (core plugs). The new approach involved analysis of rate and/or pressure data from the core test analogously to larger-scale well-test/production data. Although this approach offers some advantages over conventional pressure-decay and pulse-decay test analysis procedures, there are some practical issues related to core measurements to support the analysis that need to be addressed. For example, injection or production rate measurements, which are difficult to perform, were required to implement some of the analysis procedures. Further, in the original work, constant injection rates for the injection/falloff portion of the test, and constant flowing pressures for the production portion of the test, were assumed. In this work, we demonstrate that accurate measurement of injection rates is not necessary to obtain an accurate estimate of permeability and that the analysis methods can be applied for variable injection rates and flowback pressures.
Several permeability estimates are possible during a single test cycle using the procedures described in this work. Permeability may be estimated from the injection/falloff cycle of the test by 1) identifying the end of transient (linear) flow from derivative techniques combined with the distance of investigation calculation and 2) applying a conventional straight-line analysis of linear flow. Two independent estimates may therefore be obtained, but the latter requires estimation of the injection rate history. Similarly, two permeability estimates may be obtained from the production (flowback) cycle of the test using the distance of investigation and straight-line approaches. Both falloff and production analysis procedures are tested by simulating constant and variable injection rates, and constant and variable flowing pressures, respectively. In some cases, particularly with variable rates/flowing pressures, it may not be possible to obtain permeability from all approaches, making multiple, redundant estimates desirable to avoid a failed core analysis. As with the original test procedure proposed by Clarkson et al. (2012), the unique properties of unconventional reservoirs may be accounted for in the new analysis procedure, such as adsorption and non-Darcy flow (slippage and diffusion), and heterogeneities may be detected and analyzed.
We believe this new technique for analyzing core data will considerably improve on current techniques for establishing permeability of unconventional reservoir samples.
Advancement in drilling and production technologies, such as horizontal drilling with multi-stage fracturing, has enabled commercial production from more challenging reservoirs, namely, tight oil formations. However, high capital costs and relatively low recovery narrow the profit from such reservoirs. CO2 EOR has provided not only an excellent opportunity to unlock more oil production, but also a chance to sequestrate more CO2 to reduce environmental footprint. However, profitability of CO2 EOR processes could rely heavily on market conditions.
While CO2 EOR reserves and CO2 storage can be quantified through compositional simulation, thorough economic analyses need to be conducted to evaluate the viability of a CO2 EOR project. The complexity of this study can be reduced significantly through experimental design. Randomized economic uncertainties, such as commodity prices, royalty scheme and incentives, CO2 sequestration credits, capital and operating cost structure, CO2 price, etc. can also be investigated with Monte Carlo simulation. This coupled approach allows us stochastically to sensitize the probability of each parameter and quantify their financial impacts on CO2 EOR projects. This methodology is extremely valuable in the assessment of risks in business, especially when uncertainties are high or the problem is rather complex, such as CO2 EOR/sequestration in tight oil reservoirs.
The remaining oil in tight oil formation, after primary and water flood, is still significant. Hence, CO2 EOR has attracted attentions from industrial partners and government regulatory bodies. This paper provides a rigorous workflow for the industry on how to appraise such projects, as well as a perspective for the governing bodies of how to transform their policies and incentives when market conditions change.