Horizontal Wells In Unconventional Reservoirs Research Articles

Pressure- and Rate-Transient Model for an Array of Interfering Fractured Horizontal Wells in Unconventional Reservoirs

Summary An analytical solution is presented for pressure- and rate-transient behavior of an array of n parallel and fractured horizontal wells in an unconventional reservoir. Wells are of equal length but otherwise of unidentical properties. Each well has an arbitrary number of uniformly spaced identical, finite-conductivity fractures and is surrounded by a stimulated reservoir volume (SRV). The properties of hydraulic fractures (HFs) and SRVs may vary from well to well. Different properties may also be assigned to the unstimulated reservoir sections between wells. Natural fractures in stimulated and unstimulated reservoir volumes are accounted for by transient dual-porosity idealization. The flow domain is divided into blocks of 1D flow under the trilinear-flow assumption. Solution for each block is obtained analytically and coupled with the solutions for the neighboring blocks by the continuity of pressure and flux at the block interfaces. Drainage volumes of wells are adjusted based on the variation of well production rates because of moving no-flow boundaries between wells. The superposition principle is applied to consider variable-production conditions as well as nonsynchronous production and shut-in schedules of wells. The final solution is in the form of a matrix-vector equation in the Laplace transform domain and inverted into the time domain numerically. The model is robust and reasonably accurate for most practical applications of single-phase oil and gas production from multiple wells in an unconventional reservoir. It is an efficient tool to assess well interference effects for different well completion designs and varying reservoir characteristics. The speed of the model makes it useful for pressure-transient and production-data analysis, as well as for the initial calibration and verification of more complex numerical models.

Challenges and best practices in interpreting crosswell strain signals to monitor multicrew zipper-fracturing operations

Crosswell strain measurements using low-frequency distributed acoustic sensing (LF-DAS) are an emerging technique to monitor hydraulic-fracture propagation. Qualitative interpretations of the strain rate data have been used to evaluate fracturing stimulation efficiency, hydraulic-fracture geometry, and crosswell communication. Limited studies have investigated the crosswell strain signals recorded by offset fibers during a zipper-fracturing treatment, though zipper fracturing becomes a routine method of stimulating horizontal wells in unconventional reservoirs. This gap will be filled in this research by presenting the methods we developed to investigate complicated LF-DAS signals. These approaches were further demonstrated using the field data sets recorded by two temporary sensing fiber cables during the zipper-fracturing operation of seven offset wells with two fracking crews operating simultaneously. By exploring, comparing, and presenting the LF-DAS data recorded in wireline and disposable fiber cables, this research shares the best practices for visualizing and interpreting crosswell strain signals. The LF-DAS data set shown in this study, is, to the best of our knowledge, one of the most complicated LF-DAS data sets ever presented. The approaches proposed here can be extended and applied to visualize and interpret different kinds of complicated LF-DAS signals recorded using permanent, wireline, and disposable fiber cables.

A new approach for flow simulation in complex hydraulic fracture morphology and its application: Fracture connection element method

Efficient flow simulation and optimization methods of hydraulic fracture morphology in unconventional reservoirs are effective ways to enhance oil/gas recovery. Based on the connection element method (CEM) and distribution of stimulated reservoir volume, the complex hydraulic fracture morphology was accurately described using heterogeneous node connection system. Then a new fracture connection element method (FCEM) for fluid flow in stimulated unconventional reservoirs with complex hydraulic fracture morphology was proposed. In the proposed FCEM, the arrangement of dense nodes in the stimulated area and sparse nodes in the unstimulated area ensures the calculation accuracy and efficiency. The key parameter, transmissibility, was also modified according to the strong heterogeneity of stimulated reservoirs. The finite difference and semi-analytical tracking were used to accurately solve the pressure and saturation distribution between nodes. The FCEM is validated by comparing with traditional numerical simulation method, and the results show that the bottom hole pressure simulated by the FCEM is consistent with the results from traditional numerical simulation method, and the matching rate is larger than 95%. The proposed FCEM was also used in the optimization of fracturing parameters by coupling the hydraulic fracture propagation method and intelligent optimization algorithm. The integrated intelligent optimization approach for multi-parameters, such as perforation number, perforation location, and displacement in hydraulic fracturing is proposed. The proposed approach was applied in a shale gas reservoir, and the result shows that the optimized perforation location and morphology distribution are related to the distribution of porosity/permeability. When the perforation location and displacement are optimized with the same fracture number, NPV increases by 70.58%, which greatly improves the economic benefits of unconventional reservoirs. This work provides a new way for flow simulation and optimization of hydraulic fracture morphology of multi-fractured horizontal wells in unconventional reservoirs.

Effect of Silica Nanoparticles on Polymer Adsorption Reduction on Marcellus Shale.

Polymers play a major role in developing rheology of fracturing fluids for multistage hydraulic fracturing horizontal wells in unconventional reservoirs. Reducing the amount of polymer adsorbed in the shale formation is essential to maintain the polymer efficiency. In this study, the ability of silica nanoparticles to minimize polymer adsorption in Marcellus shale formation at reservoir temperature was investigated. Partially hydrolyzed polyacrylamide polymers of varying molecular weights (1–12 MD), salinities (2500–50,000 ppm), polymer concentrations (100–2000 ppm), and silica nanoparticle concentrations (0.01–0.1 w/w) were used in the static adsorption experiments. Adsorption of the polymer in the Marcellus shale samples was contrasted with and without the silica nanoparticles at a Marcellus formation reservoir temperature of 65 °C, showing a significant polymer adsorption reduction of up to 50%. The adsorption and adsorption reduction were more sensitive to the variation of the polymer concentration than to the variation of the salinity within the tested conditions. The highest adsorptions were reported at the higher molecular weight of 10–12 MD. In addition, silica nanoparticles significantly improved polymer rheology at elevated temperatures. The results indicate that nanoparticles can play a significant role in reducing polymer adsorption in the fracturing fluid and improve its rheological properties and its efficiency, which will reduce the number of issues caused by the polymers in the fracturing fluid and making it more cost effective.

SERA: An ISIP analysis approach to estimate fracture height and correlate stress escalation and relaxation in multifrac horizontal wells

In hydraulic fracturing of horizontal wells in unconventional reservoirs, every fracturing stage by increasing the minimum horizontal stress modifies the vertical stress contrast as well as reduces the stress anisotropy. The induced stress gradually declines thereafter due to fracture closure caused by fluid leak-off. The time-dependent stress behavior with localized spatial effects generated by fixed but dynamic sources offers an incentive to fracturing optimization studies. Here, drawing upon the stress superposition principle, an analytical model is derived for Stress Escalation and Relaxation Analysis (SERA) to correlate the stress state at the wellbore. The SERA's model possesses a set of tuning parameters that are adaptively adjusted based on perforation design, waiting time between stage treatments, and ISIP of all completion stages. As a computationally efficient ISIP analysis technique, SERA estimates the average height of wet fracture and sets an upper limit to the critical stress state. In case of a dominant vertical stress contrast, SERA allows to determine explicitly the conditions under which the onset of wet fractures into the bounding layers of lower stress takes place, and when the stress re-orientation controls the fracturing regime, it narrows down the range of estimates of the horizontal stress anisotropy. Furthermore, it provides a tool to design optimal timing and sequencing strategies for alternating fracturing by correlating post-treatment stress relaxation parameters. We validate the model with numerical simulations and perform a sensitivity analysis on the influential parameters that can be carefully designed to give more control over stress shadowing.

A semianalytical well-testing model of fracture-network horizontal wells in unconventional reservoirs with multiple discretely natural fractures

Microseismic data shows that some unconventional reservoirs comprise well-developed natural fractures and complex hydraulic fracture networks. It is neither practical nor advantageous to simulate a huge number of natural and hydraulic fractures with numerical models. Given that the conventional dual-porosity models are not applicable to the highly discrete natural fractures, the paper develops a semianalytical well testing model for horizontal wells with hydraulic fracture networks and randomly-distributed discretely natural fractures.The proposed model has the capability to analyze the pressure behaviors by considering complex fracture networks and isolated natural fractures rapidly and efficiently. The model includes diffusivity equations in three domains: (1) matrix, (2) discretely natural fractures, and (3) hydraulic fracture networks. The pressure transient solution of these diffusivity equations is obtained by using Laplace transforms and superposition principle. We verify the presented model by performing a case study with a numerical simulator for complex natural fractures.It is found that there are some interesting flow behaviors for fracture-network horizontal well with discretely natural fractures like bilinear flow, “V-shape” caused by fluid supply, pseudo boundary-dominated flow, impact of natural fractures, etc. The pseudo boundary-dominated flow provides us the information about how large the area covered by hydraulic fracture networks. The impact of natural fracture shows the parameters of natural fractures. This work provides a good understanding of transient pressure behaviors in unconventional reservoirs and guidelines for the producer optimize field development and well economics.

Fracture Propagation Characteristics in Horizontal Wells

Field experience shows that horizontal well multi-stage fracturing technology can transform the volumetric pressure crack network in the formation and has been widely used in unconventional oil and gas resource exploitation. According to the requirements of horizontal well fracturing operations, this paper simulates the law of horizontal well fracturing in low-porosity and low-permeability sand-shale formation by large-mold fracturing tests and analyzes crack initiation and extension. The two completion methods of open-hole completion and casing perforation completion are considered, and the maximum and minimum horizontal principal stress difference is 10 and 4 MPa. The horizontal wellbore azimuth angle changes from 0° to 90°. The test results show that the principal stress difference has a great influence on fracture initiation. The smaller the stress difference, the higher the fracture initiation pressure and the more complicated the fracture initiation and extension. The fracture propagates along the axial direction of the wellbore, and then at both ends of the wellbore the fracture turns to the direction perpendicular to the direction of the minimum horizontal principal stress. The horizontal wellbore can form a transverse fracture by drilling along the direction of the minimum horizontal principal stress. This study is of great significance for understanding the fracture initiation and propagation law of horizontal well fracturing and can provide guidance for multi-stage fracturing operations of horizontal wells in unconventional reservoirs.

Three-Dimensional Projection-Based Embedded Discrete-Fracture Model for Compositional Simulation of Fractured Reservoirs

Summary Most unconventional oil and gas reservoirs are known to have several natural fractures in different orientations, which are consistent with the prevailing stresses when they were created. The accurate and efficient modeling of natural and hydraulic fractures presents a significant computational challenge. In this work, we show the limitations of the embedded discrete-fracture model (EDFM) and present the first 3D projection-based EDFM (pEDFM) algorithm and compositional simulation studies with realistic fracture networks in a fully 3D space. The simulation results from this work indicate that the pEDFM presented can model realistic fractured unconventional reservoirs accurately and efficiently. To validate the model, we present some simplistic fracture cases that can be meshed and modeled easily using explicit-fracture modeling in commercial-reservoir simulators. From the cases studied, we observe that using progressively finer grids near the hydraulic-fracture surfaces helps to improve model accuracy because this allows us to capture the sharp pressure drops expected near these fracture surfaces. The simulation results show that, unlike EDFM, the robust pEDFM algorithm presented here is accurate even at the low fracture-conductivity values expected in many of these ubiquitous natural fractures. In this paper, we present the first full 3D compositional modeling with pEDFM. We demonstrate that our model can accurately and efficiently model multiply fractured horizontal wells in unconventional reservoirs, which have complex networks of thousands of fractures at various orientations.

Production-Decline Models Using Anomalous Diffusion Stemming From a Complex Fracture Network

Summary In this work, we develop a well–based fractional–production–decline model, which resorts to anomalous diffusion to characterize the heterogeneity of complex fracture networks and can be conveniently used to interpret the rate and cumulative data in the early and middle times of production from multifractured horizontal wells in unconventional reservoirs. We first develop a model (the fracture–based model) to be used in inverse problems by simplifying the fractional–time–derivative model using the traditional multiple–planar–fracture framework to essentially contain three parameters (α,Ar, and Ix). After performing tests with elaborate synthetic cases, the trace of anomalous diffusion is captured but the drawbacks of this model are also detected and analyzed. Then, by focusing on improving the fracture–based model, we consider an infinite–conductivity horizontal well draining a complex fracture network through a fractional–flux–related skin. The improved model (the well–based model) is bolstered with the corresponding type curves regarding production rate and cumulative production, which can be applied to interpret the single–phase production in the early and middle times and to mainly characterize the fracture–network–related heterogeneity reflected in the production data during this early–to–middle period. The well–based model is applied to two synthetic cases with explicitly modeled complex fracture networks and to the cases of multifracture horizontal wells in the Permian Basin. The results of all case studies display good matches between our model and the production data, which indicates the model's capability to accurately describe the transient regime of the flow in the extremely heterogeneous fracture networks on the basis of average values of the formation properties.

Inversion of Downhole Temperature Measurements in Multistage-Fracturing Stimulation of Horizontal Wells in Unconventional Reservoirs

Summary There are still many challenges involved with the quantitative interpretation of downhole distributed-temperature measurements for diagnosing multistage-fracturing treatments in horizontal wells. These challenges include handling enormous amounts of data measured by the sensors in a continuous time and space domain, a ready-to-use fast and robust forward model to simulate temperature behavior, and an efficient algorithm to invert the parameters that are of interest. Because multistage fracturing involves many uncertain parameters (ranging from reservoir properties to treatment design, to fracture geometries and conductivity), the problem becomes extremely complicated when the measured temperature is inverted to a downhole flow profile. In this study we present an approach for combining forward and inverse models to interpret downhole temperature data. Our goal was to improve computational efficiency. Field data from a gas well in the Marcellus Shale were used to illustrate the feasibility of quantitative interpretation of temperature measurement for fracture diagnosis. The forward model used the fast-marching method (FMM). The forward simulation was an order of magnitude faster than the semianalytical model, which is the essential contribution for successfully applying the method in the field case. The improved inversion procedure increased the efficiency of the interpretation. The inversion procedure began with a sensitivity study to select the inversion parameters among various other parameters, such as fracture half-length and the fracture conductivity, and to determine the impact of their uncertainty on inversion. The inversion model used the initial analysis of the temperature gradient to identify the fracture locations with significant temperature changes for interpretation and eliminated the rest of the fracture locations from interpretation. Thus, we obtained a prior estimation of the selected inversion parameters, which was used as an initial estimate for the inversion process. This prior estimation saved significant computation. The inversion was performed fracture by fracture using either parallel computing or sequential computing on the basis of the sensor locations. We began with a synthetic example containing multiple fractures to illustrate the approach and test the procedure accuracy and computation speed. The primary inversion parameter was flow rate, though we also interpreted either fracture length or fracture conductivity when assuming all the other parameters as additional constraints. With an adequate initial estimate, the inverted parameters matched the reference “true value” properly. The inversion process converged with reasonable iterations for each fracture (2–3 iterations). The operation time highlights the advantages of the inversion approach presented in this paper. The guided initial estimation ensured that the gradient inversion approach converged and avoided local minimization. Finally, a field application for interpreting the DTS measurement for the flow profile of the multistage-fractured horizontal well was performed using this inversion method, and it showed encouraging results. The results of our investigation illustrate the procedure feasibility for using temperature data to diagnose a multistage-fracturing treatment. Our proposed inversion model was fast and reliable and provided a promising tool that can be used to quantitatively interpret downhole temperature data.

Semianalytical Solution for Modeling the Performance of Complex Multifractured Horizontal Wells in Unconventional Reservoirs

Summary Analytical models have evolved in their capacity to represent the transient response of multifractured horizontal wells producing from unconventional reservoirs. However, as is common with analytical solutions, they are based on simplified reservoir/well geometries and flow-pattern assumptions that inherently restrict their scope of application. Their use for analyzing flow scenarios that transcend their scope is thus prone to errors. This paper documents a semianalytical model that overcomes the aforementioned limitations, and thereby expands analysis to the realm of reservoir/well architectures that are inaccessible to analytical models. Our solution is based on the Laplace-transform boundary-element-method (BEM) implementation of the Green's function solution of the diffusivity equation. We represent the reservoir as a 2D composite system, with the outer boundaries and the interface between reservoir regions discretized appropriately. With the collocation procedure, the solution is distilled to a system of algebraic equations that is solved for the reservoir's transient response. The hydraulic fractures need not be regular (equidistant and/or isometric), as is required by most analytical models; instead, they can traverse arbitrary spatial orientations and dimensions with respect to the horizontal well. We demonstrate the application of our solution by modeling multifractured-horizontal-well performance with two verification cases and three synthetic examples. The first example showcases a multifractured horizontal well traversed by identical, evenly spaced, fully penetrating, vertical hydraulic fractures within a stimulated reservoir volume (SRV). The second example models an enhanced-permeability region local to each hydraulic fracture as opposed to a single SRV housing all the fractures. The last example typifies complex fracture geometries, where the fractures have different half-lengths, spacings, and orientations. Besides showing that all the verification and example cases are in excellent agreement with numerical solution, we demonstrate the utility of our solution for modeling variable-rate flow commonly observed in practical field-production scenarios, showing its potential for history matching and forecasting the performance of multifractured horizontal wells.

History Matching and Rate Forecasting in Unconventional Oil Reservoirs With an Approximate Analytical Solution to the Double-Porosity Model

Summary Production data from most fractured horizontal wells in gas and liquid-rich unconventional reservoirs plot as straight lines with a one-half slope on a log-log plot of rate vs. time. This production signature (half-slope) is identical to that expected from a 1D linear flow from reservoir matrix to the fracture face, when production occurs at constant bottomhole pressure. In addition, microseismic data obtained around these fractured wells suggest that an area of enhanced permeability is developed around the horizontal well, and outside this region is an undisturbed part of the reservoir with low permeability. On the basis of these observations, geoscientists have, in general, adopted the conceptual double-porosity model in modeling production from fractured horizontal wells in unconventional reservoirs. The analytical solution to this mathematical model exists in Laplace space, but it cannot be inverted back to real-time space without use of a numerical inversion algorithm. We present a new approximate analytical solution to the double-porosity model in real-time space and its use in modeling and forecasting production from unconventional oil reservoirs. The first step in developing the approximate solution was to convert the systems of partial-differential equations (PDEs) for the double-porosity model into a system of ordinary-differential equations (ODEs). After which, we developed a function that gives the relationship between the average pressures in the high- and the low-permeability regions. With this relationship, the system of ODEs was solved and used to obtain a rate/time function that one can use to predict oil production from unconventional reservoirs. The approximate solution was validated with numerical reservoir simulation. We then performed a sensitivity analysis on the model parameters to understand how the model behaves. After the model was validated and tested, we applied it to field-production data by partially history matching and forecasting the expected ultimate recovery (EUR). The rate/time function fits production data and also yields realistic estimates of ultimate oil recovery. We also investigated the existence of any correlation between the model-derived parameters and available reservoir and well-completion parameters.

New analytical functions for a skin and storage effect – An insight to decouple fracture half-length and square-root of permeability

Several solutions to the double porosity model have been presented. There are solutions for closed outer boundary systems as well as infinite acting boundary conditions with constant rate or constant pressure inner boundary conditions. A common assumption in all of these solutions is that the fracture has a quadrilateral (linear) geometry. Very few solutions exist for cases were the fracture is assumed to have a circular geometry. This is the first work that presents approximate early and late time solutions for flow from fractures that have a circular geometry where the inter porosity transfer function is model with an unsteady state function. The result obtained from this analysis shows that the function behaves in a manner identical to production data from fractured horizontal wells in unconventional reservoirs (including early time data that is usually assumed to be obscured by skin and wellbore/fracture storage effects).The double porosity model was formulated for a fractured horizontal well in which the fractures were assumed to have a circular geometry. The associated mathematical model was then solved with Laplace transforms to obtain a closed form analytical solution in Laplace space. We then derive the approximate early and late time solutions by using special properties of Bessel functions and the Laplace space solution. The solutions were derived for a constant-pressure and constant-rate inner-boundary condition with a no flow outer-boundary condition.The approximate early time solution obtained is identical to the solution obtained when the fracture is assumed to have a quadrilateral geometry. But it has two additional parameters. A detailed sensitivity analysis showed that fracture thickness does not have a significant impact on the producing characteristics. The approximate late-time solution has a production history identical to that observed from field production data. The approximate late-time solution also has a slope of two on a log–log plot of rate verses time; this has not been report before in the literature. A comparison of the approximate late-time solution to traditional linear fracture solutions with skin and storage effect lead to the development of new skin and fracture storage functions. The significance of this result is that the new skin and fracture storage functions suggest that they can be used to decouple the product of fracture half-length and the square-root of permeability from early-time production data.

Analysis of Decline Curves on the Basis of Beta-Derivative

Summary This paper presents a new simplified method for forecasting oil and gas production during transient and boundary-dominated flow (BDF), which does not require the use of complex analytical or numerical modeling tools. The method is based on the behavior of the beta-derivative (β), where two approximate straight lines are obtained during transient flow and BDF with slopes mt and mb, respectively. The method is applicable not only to vertical wells in conventional reservoirs producing during BDF but also to hydraulically fractured vertical/multifractured horizontal wells in unconventional reservoirs with prevailing transient (linear) flow. Upon selection of an appropriate βBDF—which mainly depends on the type of flow regime (i.e., radial or linear)—and using the proposed equations, type curves can be generated that provide a convenient method for obtaining the slopes of beta-derivatives for transient flow (mt) and BDF (mb) through a type-curve matching process. The method is validated by comparing results against oil and gas numerical simulations of vertical and hydraulically fractured vertical wells. The developed method is not biased toward any flow regime or presence of skin. Flow regime and skin effects are embedded in the βBDF and mt parameters. Transient flow and BDF are accounted for through the slopes mt and mb, respectively. Corroborated with the use of numerical simulation and field data from the Western Canada Sedimentary Basin and Mexico, the proposed method provides reliable production-rate forecasting while staying away from the complexities of analytical or numerical modeling.

A mathematical model considering complex fractures and fractal flow for pressure transient analysis of fractured horizontal wells in unconventional reservoirs

This article is the first investigation on the fracture network heterogeneity flow for multiple fractured horizontal wells in unconventional reservoirs. Currently, most modeling approaches for multiple fractured horizontal wells are based on flow in several distinct scales (matrix/fracture), in which the network of fractures is assumed to be connected and equivalent to a homogeneous medium of Euclidean geometry. To account for more detailed description of unconventional reservoir, fractal permeability and porosity relationship was introduced to represent reservoir heterogeneity. Fractal flow in a dual-continuum porous medium is taken into consideration to establish a model of hydraulically fractured horizontal wells. The coupled fractal-based tri-linear diffusivity equation helps illuminate the reservoir performance and improve the pressure transient analysis. A tri-linear flow mathematical model is used to represent the flow in hydraulic fractures, in the formation between the fractures, and in the formation away from the hydraulic fractures. To solve the equations at different regions, we prescribe the proper boundary conditions and use Laplace transformation and numerical inversion from the Laplace domain to the time domain. The new semi-analytical solutions were validated via numerical simulations.The type curve of fractal pressure transient behavior was thoroughly examined; which were found to be primarily dependent on the value of the fractal parameters chosen. The proposed model could be used to diagnose the flow regime and interpret the pressure response more accurately for shale/tight oil reservoirs.

Integrated Completion Design for Horizontal Wells in Unconventional Reservoirs

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 147120, ’An Integrated Approach To Design Completions for Horizontal Wells in Unconventional Reservoirs,’ by R. Jain, SPE, S. Syal, SPE, T. Long, SPE, and C. Wattenbarger, SPE, ExxonMobil, and I. Kosik, SPE, Imperial Oil Resources, prepared for the 2011 SPE Annual Technical Conference and Exhibition, Denver, 30 October-2 November. The paper has not been peer reviewed. An integrated workflow was tested for designing completions for a heavy-oil-recovery process that involves injection and production through the same wellbore. To capture the effect of variations or uncertainties in reservoir and fluid-flow characteristics over time, the transient effects are particularly important while analyzing the long-term performance for these types of completions. The proposed integrated workflow involves initial screening and selection of flow-restricting completions that can meet the desired injection and production performance on the basis of a detailed wellbore-hydraulics-modeling tool. Introduction Producing heavy oil and bitumen involves technologies such as cold mining for shallower resources or in-situ viscosity reduction. The cyclic solvent-based process involves alternating cycles of injecting a viscosity-reducing solvent into the reservoir followed by production of a mixture of heavy oil and solvent, with reduced viscosity, through the same wellbore. Many cyclic-process implementations are intended for use in horizontal wells. The completion design for such a process involves ensuring good solvent distribution into the reservoir during the injection phase to mobilize the resource along the entire wellbore and maximize the well length to reduce field-development cost. The process of injecting and producing from the same wellbore entails additional constraints on the completion design. One constraint is controlled injection distribution by use of flow-restriction devices such as orifices while maintaining a minimal pressure drop across the completion during the production phase. Another challenge results from the adverse mobility ratio of the solvent mixture and bitumen during the injection process, which could result in viscous fingering. This fingering can cause wide variations in the solvent injection and may cause an undesirable pressure distribution within the reservoir, which, in turn, may affect solvent placement. Predicting such differential injection or a thief zone is difficult because of the inherent nature of instabilities associated with the fingering process.

Investigating Liquid Loading in Tight Horizontal Gas Wells

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 149477, ’Investigation of Liquid Loading in Tight Horizontal Gas Wells With a Transient-Multiphase-Flow Simulator,’ by Donald F.B. Jackson, SPE, SPT Group, and Claudio J.J. Virues, SPE, and David Sask, SPE, Encana, prepared for the 2011 Canadian Unconventional Resources Conference, Calgary, 15-17 November. The paper has not been peer reviewed. Liquid loading occurs in gas wells when production declines to a rate that is insufficient to lift the associated liquids to the surface. Liquid holdup in the horizontal section may impair production before liquid loading in the production tubing becomes evident. Holdup in the horizontal section can lead to slug flow at the tubing and to early onset of liquid loading in the tubing. The results from a transient-multiphase-flow model were found to be consistent with data acquired from video logging. Sensitivity analyses were performed with several normalized trajectories. Introduction Technology applied in conventional reservoirs in offshore horizontal wells can be applied successfully in onshore horizontal wells in unconventional reservoirs. The Jean Marie formation is an Upper Devonian carbonate platform between two thick shale layers in the Greater Sierra area, approximately 90 km east of Fort Nelson, British Columbia, Canada. The formation has low porosity (averaging 6%), low water saturation (averaging 20%), and low permeability (less than 1 md to air). Formation depth ranges from 600 to 1500 m subsea—1000- to 1900-m true vertical depth. The formation is entirely gas saturated with a dry sweet gas (95% methane) and is variably underpressured, with initial reservoir pressures of 6 to 15 MPa. The horizontal wells are drilled underbalanced to limit formation damage. Fig. 1 shows a typical well completion with 177.8-mm production casing set at the top of the Jean Marie formation. Gas is produced from the openhole portion of the completion. While drilling horizontally through the Jean Marie formation, the well trajectory is steered on the basis of gas-rate-while-drilling (RWD) data. The geologists maneuver up and down in inclination until a good permeability streak is indicated by a spike in flow rate from the RWD data. After reaching target depth, tubing (typically 60.3 mm) is installed and the well is brought on production. Typical gas- production rates for Jean Marie wells decline from an initial rate of 56×103 m3/d to 14×103 m3/d after 12 months and to 10×103 m3/d after 36 months.

Practical Solutions for Pressure-Transient Responses of Fractured Horizontal Wells in Unconventional Reservoirs

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 125043, ’Practical Solutions for Pressure-Transient Responses of Fractured Horizontal Wells in Unconventional Reservoirs,’ by M. Brown, SPE, and E. Ozkan, SPE, Colorado School of Mines; R. Raghavan, SPE, Phillips Petroleum Company (Retired); and H. Kazemi, SPE, Colorado School of Mines, prepared for the 2009 SPE Annual Technical Conference and Exhibition, New Orleans, 4-7 October. An analytical trilinear-flow solution was developed to simulate the pressure-transient and production behavior of fractured horizontal wells in unconventional reservoirs. This solution provides an alternative to rigorous solutions, which can be cumbersome to evaluate. These solutions provide insight about and the conditions leading to these flow regimes. Identifying these flow regimes is important to characterize unconventional reservoirs from pressure-transient tests. Introduction Although it is possible to develop detailed analytical models to represent transient fluid flow toward a multiple-fractured horizontal well in tight unconventional reservoirs such as shale, the difficulties of these models are the increased computational requirements, the implicit functional relationships of key parameters, and the inconvenience of their use in iterative applications. Despite the complex interplay of flow among matrix, natural fractures, and hydraulic fractures, the key characteristics of flow convergence toward a multiple-fractured horizontal well may be preserved in a relatively simple, trilinear-flow model. The basis of the trilinear-flow model is that the productive lives of fractured horizontal wells in tight formations are dominated by linear-flow regimes. Physical Model and Assumptions For hydraulically fractured horizontal wells in unconventional reservoirs with microdarcy matrix permeabilities (such as shale), the contribution of the reservoir beyond the stimulated volume usually is negligible. Hydraulic fracturing also changes the stresses in the fracture-drainage area, which may create or rejuvenate natural fractures near the horizontal well. Under these conditions, flow convergence is mainly in the linear direction perpendicular to the surfaces of the hydraulic fractures, and, despite the complex interplay among matrix, natural fractures, and hydraulic fractures, a relatively simple, trilinear-flow model may represent the key characteristics of flow toward a multiple-fractured horizontal well. The trilinear-flow model couples linear flows in three contiguous flow regions, as shown in Fig. 1: the outer reservoir beyond the tips of the hydraulic fractures, the inner reservoir between hydraulic fractures, and the hydraulic fracture. Each region can have distinct properties. The inner reservoir may be homogeneous or naturally fractured, and the hydraulic fractures may have finite conductivity.