Determining the Effectiveness of Isolation Techniques Using Completion Diagnostics and Production Analysis

Integration of microseismic and other post-fracture surveillance with production analysis: A tight gas study

Owing to the low productivity of single well, rapid productivity decline and low ultimate recovery of low-permeability reservoirs, multistage fracturing is usually employed for reservoir stimulation of horizontal wells, which helps to increase fracture conductivity and single well productivity by creating artificial fractures. It is very vital to accurately characterize and simulate 3D spatial distribution of fracture networks for hydraulic fracturing technology. Sufficient production data has proved that the hydraulic fracture geometry simulation integrating 1D geomechanics, without considering natural fractures, resulted in low accuracy of fracture modeling, which could not effectively support the deployment and implementation of oilfield development plan. Thus, artificial fracture networks simulation technology fully coupling 3D geomechanics with natural fracture model will be urgently required to guide oilfield development economically. The technical research process is divided into 4 steps. Step 1, set up 1D geo-mechanical modeling in single well using conventional and image logging data, formation integrity testing, drilling logs, as well as rock mechanical laboratory tests. Then, 3D static geomechanical modeling of the reservoir can be performed by incorporating seismic data and structural modeling. Step 2, identify natural fractures in single well based on image logging data and core data to create fracture intensity curve modeling. Establish 3D natural fracture model constrained by fracture sensitive seismic attributes analysis and 3D fracture intensity trend body. Step3, based on rock and fracture mechanics, simulate hydraulic fracture extension of stimulated well coupling 3D geo-mechanical model with 3D natural fracture model. Then, verify modeling accuracy through micro-seismic data. Step 4, compare and analyze differences in fracture geometry, proppant placement, and fracture conductivity between 3D coupled fracture modeling (3DCFM) and 3D uncoupled fracture modeling (3DUFM). After gridding 3DCFM and 3DUFM to geological modeling, predict production post fracturing using numerical simulation technology. Finally, crosscheck the accuracy of 3DCFM and 3DUFM with predicted and actual production data. By comparing and analyzing the fracture geometry and numerical simulation results of 3DCFM and 3DUFM, it was concluded that 3DUFM could not characterize natural fracture shielding effect and diversion during fracture extension due to 3D geo-mechanical spatial anisotropy. Thus, greater uncertainties of the fracture modeling occurred, resulting in low consistency between single well productivity prediction and numerical simulation. Compared with 3DUFM, the uncertainty of the fracture modeling geometry can be greatly reduced in 3DCFM verified by micro-seismic patterns, so the consistency between productivity prediction and numerical simulation will be significantly increased. Hydraulic fracture simulation technology fully-coupling geomechanics with natural fracture model was applied in the low permeability fractured reservoirs of the northwestern margin of Junggar Basin, China. The cross-over analysis among research results, the actual micro-seismic patterns and production data indicated that compared with 3DUFM, the uncertainty of 3DCFM reduced by 25.2%;, and the consistency of numerical simulation and productivity prediction increased by 18.5%. The research results would be a guideline on location optimization of horizontal wells, stimulation optimization of multistage fracturing and strategy optimization of oilfield development.

PreviousNext No AccessUnconventional Resources Technology Conference, Denver, Colorado, 12-14 August 2013Determining the Contributing Reservoir Volume from Hydraulically Fractured Horizontal Wells in the Wolfcamp Formation in the Midland BasinAuthors: Mickey FriedrichMike MillikenMickey FriedrichPioneer Natural ResourcesSearch for more papers by this author and Mike MillikenPioneer Natural ResourcesSearch for more papers by this authorhttps://doi.org/10.1190/urtec2013-149 SectionsAboutPDF/ePub ToolsAdd to favoritesDownload CitationsTrack CitationsPermissions ShareFacebookTwitterLinked InRedditEmail Abstract URTeC 1582170 This paper provides a methodology that is practical and logical in its approach to provide answers involving the evaluation and development of unconventional reservoirs. Multiple sources of data are analyzed to estimate the effectively stimulated volume of reservoir for horizontal wells in the Wolfcamp formation in the Midland Basin of west Texas. Estimating this volume is critical in determining optimum spacing and stacking of horizontal wellbores in unconventional reservoirs. Stimulated Reservoir Volume (SRV), as determined from microseismic, locates seismic events due to rock failure but does not necessarily represent the reservoir volume contributing to production. The reduced volume contributing to production is defined as the Contributing Reservoir Volume (CRV). This paper presents a workflow of using three methods - interpreted microseismic, proppant material balance, and calibrated hydraulic fracture modeling - to collectively estimate the CRV in hydraulically fractured horizontal Wolfcamp wells. Microseismic data is interpreted both by applying a discount factor based on industry studies and by analyzing locations and concentrations of events. Then a method of proppant material balance is used to estimate the maximum propped dimensions based on the mass of sand that is placed in each cluster of perforations. Finally, a calibrated geomechanical hydraulic fracturing model is used to model the CRV of 25 wells drilled in the Wolfcamp throughout the study area. Keywords: horizontal wells, fractures, unconventional, stacking, modelingPermalink: https://doi.org/10.1190/urtec2013-149FiguresReferencesRelatedDetailsCited ByA mathematical model for estimating effective stimulated reservoir volume24 November 2021 | Journal of Petroleum Exploration and Production Technology, Vol. 12, No. 7Analysis of Mancos Shale gas production scenarios under various stress mechanisms24 August 2021 | Arabian Journal of Geosciences, Vol. 14, No. 18A Review of Flow Mechanism and Inversion Methods of Fracture Network in Shale Gas ReservoirsGeofluids, Vol. 2021Production Interference of Hydraulically Fractured Hydrocarbon Wells: New Tools for Optimization of Productivity and Economic Performance of Parent and Child Wells3 June 2019Unconventional Reservoir Geomechanics14 June 2019 | , Vol. 1Surmounting Paucity of Data in Hydraulic Fracture Designs: Case Studies From the Permian Basin23 April 2018Case Study for Effective Stimulated Reservoir Volume Identification in Unconventional ReservoirsJournal of the Korean Society of Mineral and Energy Resources Engineers, Vol. 55, No. 2PKN Solution Revisit: 3-D Hydraulic Fracture Size and Stress Anisotropy Effects24 October 2017 | Rock Mechanics and Rock Engineering, Vol. 51, No. 2Performance-based fractal fracture model for complex fracture network simulation22 December 2017 | Petroleum Science, Vol. 15, No. 1Method of Characterization of Complex Fracture Network with Combination of Microseismic using Fractal theory17 October 2017Case History - Continued Diagnostic Technology Integration with Completions in Horizontal Wolfcamp Shale Wells in the Delaware Basin9 October 2017Midland Basin Wolfcamp Shale: Completions Observations and Lateral Length OptimizationKyle M. Richter12 September 2017Application of the fractal geometry theory on fracture network simulation23 July 2016 | Journal of Petroleum Exploration and Production Technology, Vol. 7, No. 2Deciphering Dynamic Fracture Systems through Multiple Monitoring Wells with Permanent Downhole Gauges in the Midland BasinYula Tang, Baosheng Liang, and Leif Larsen3 August 2016Understanding Wolfcamp Well Performance - A Workflow to Describe the Relationship between Well Spacing and EURJared Pettegrew*, Jiale Qiu, and Lang Zhan3 August 2016Application of Real-Time Bottom-Hole Pressure to Improve Field Development Strategies in the Midland Basin Wolfcamp ShaleKyle D. Scott*, Wei-Chun Chu, and Raymond W. Flumerfelt12 August 2015The role of hydraulic fracture geometry and conductivity profile, unpropped zone conductivity and fracturing fluid flowback on production performance of shale oil wellsJournal of Unconventional Oil and Gas Resources, Vol. 9Application of Real-Time Bottom-Hole Pressure to Improve Field Development Strategies in the Midland Basin Wolfcamp Shale4 August 2015Proper Inclusion of Hydraulic Fracture and Unpropped Zone Conductivity and Fracturing Fluid Flowback in Single Shale Oil Well Simulation17 April 2014Well-Spacing Study to Develop Stacked Tight Oil Pay in Midland Basin1 April 2014Estimation of Stimulated Reservoir Volume Using the Concept of Shale Capacity and its Validation with Microseismic and Well Performance25 February 2014 Unconventional Resources Technology Conference, Denver, Colorado, 12-14 August 2013ISSN (online):2159-6832Copyright: 2013 Pages: 1229 publication data© 2013 Published in electronic format with permission by the Society of Exploration Geophysicists, American Association of Petroleum Geologists, and Society of Petroleum EngineersPublisher:Unconventional Resources Technology ConferenceSociety of Exploration Geophysicists HistoryPublished: 26 Sep 2013 CITATION INFORMATION Mickey Friedrich and Mike Milliken, (2013), "Determining the Contributing Reservoir Volume from Hydraulically Fractured Horizontal Wells in the Wolfcamp Formation in the Midland Basin," SEG Global Meeting Abstracts : 1461-1468. https://doi.org/10.1190/urtec2013-149 Plain-Language Summary Keywordshorizontal wellsfracturesunconventionalstackingmodelingPDF DownloadLoading ...

Present trends towards using high frequency and big data such as SCADA allow the acquisition of large set of well data ranging over much longer periods of time than previously imaginable such as total production history. Such production and pressure data can contain information about the reservoir at a substantially larger radius of investigation than that accessible to unconventional derivative analysis, which is limited to the interpretation of single flow periods at constant rate. By contrast, deconvolution methods, do not suffer from this constraint as they are designed to perform well production and pressure data analysis at variable flow rate. In this work, we present a deconvolution method applied to multi-fractured horizontal shale gas wells. This work offers a new solution method to the long-standing deconvolution problem and makes deconvolution a viable tool for well-test and production and pressure data analysis. The following objective is proposed for this work: To apply this method to traditional variable-rate/pressure problems, such as long-term production data, high SCADA frequency pressure gauge data and well tests having multiple wells producing. This paper will show the deconvolution method based on the work of Von Schroeter et al and Michael Levitan et al. Deconvolution is a mathematical tool that extracts the drawdown type curve from the rate and pressure history. Essentially, the deconvolution process consists of the following steps: Generate a typecurve as an initial guess Superimpose this typecurve with historical rate data to calculate synthetic pressures Calculate the error between the calculated pressures and the measured pressures Generate a new typecurve and repeat the process until the error between calculated and measured pressures is minimized Deconvolution techniques provide an alternative to unconventional diagnostic analysis, and can show additional flow regime information that would not normally be seen within the specified time-frame of the buildup test. The deconvolved typecurve can then be analyzed for each multi-fractured shale gas horizontal well using unconventional diagnostic analysis techniques to determine various reservoir characteristics such as Stimulated Reservoir Volume (SRV) fracture half length, permeability, skin, reservoir size, effective wellbore length, effective stimulated stages, and more. We validate our work with examples using daily and minute data. Upon validation, we then demonstrate the deconvolution method using a variety of field cases, including traditional well tests, turnaround wellhead gauge data as well as production data of multi-fractured horizontal wells. Our work suggests that the deconvolution method has broad applicability in variable rate/pressure problems and can be implemented in typical well test and production data analysis applications. This study highlights not only the need of combining different frequency and quality controlled data but also pressure and rate type of data as well to get a full understanding of various reservoir characteristics within the SRV.

The impacts of the fluid type and stress shadow on proppant transport during hydraulic fracturing in a Marcellus shale horizontal well with multiple hydraulic fracture stages were investigated. The available data from a Marcellus Shale horizontal well were utilized to determine the hydraulic fracture properties and to develop a reservoir model. The reliability of the model was confirmed by the close agreement between the predicted production by the model and the well production data. The impact of fluid type and stage spacing on proppant transport during hydraulic fracturing and gas production from Marcellus shale horizontal well were then investigated by employing the reservoir models. Slickwater, compared to crosslinked gels and high viscosity friction reducers (HVFRs), is more efficient in horizontal Marcellus shale wells that are fractured in multiple stages. The application of the HVFRs and crosslinked gels resulted in fracture height growth out of the pay zone. While the use of slickwater directed all stimulation energy towards the pay zone and resulted in improved hydraulic fracture properties in the Marcellus shale and lead to high gas recovery. INTRODUCTION The advancements in horizontal drilling and hydraulic fracturing technologies have made shale production a reality for the past decade. With the technical and economical limitations posed by hydraulic fracturing operations in unconventional reservoirs, it is imperative to create an optimized fracturing design to achieve economic production. A number of treatment design considerations including the type of fluid, proppant type and size, and the additives must be evaluated to achieve successful well stimulation results. In general, proppant transport is dependent on proppant size, density, and type; fluid rheology; temperature changes; pumping rate, among others. The fracturing fluid should be compatible with the formation and promote the increase in the stimulated volume. In order to transport the proppants deep into the fracture, the fluid should be capable of keeping the proppants suspended. With an inherent viscosity, fluid should be able to develop the necessary fracture width to accept proppants. Also, it should have low friction pressure loss and sufficient stability to retain its viscosity throughout the treatment and finally, it should be easy to remove after the treatment. The type of fluid used therefore has pronounced impact on the transport of proppants and the properties of the created hydraulic fracture and consequently the hydrocarbon production. Proppant selection is a contributing factor in the dimensions of a propagating fracture. The most prevalent hydraulic fracturing treatment fluids in shale formations is slickwater with no significant amount of thickening agent. The application of this low viscosity fluid system contradicts conventional fracturing theory. However, slickwater is the preferable fracturing fluid in shale because of its cost-effectiveness and low potential for damaging the shale. In addition, slickwater has the potential to prevent high fracture height growth leading to better fracture containment within the pay zone.

Reliable estimates of hydraulic fracture geometry help reduce the uncertainty associated with estimated ultimate recovery (EUR) forecasts and optimize field developing planning in unconventional reservoirs. For these reasons, operators gather information from different sources with the objective to calibrate their hydraulic fracture models. Microseismic data is commonly acquired by operators to estimate hydraulic fracture geometry and to optimize well completion designs. However, relying solely on estimates derived from microseismic information may lead to inaccurate estimates of hydraulic fracture geometry. The objective of this study is to efficiently calibrate hydraulic fracture geometry by using microseismic data, physics-based fracture propagation models, and the embedded discrete fracture model (EDFM). We first obtain preliminary estimates of fracture geometry based on microseismic events’ spatial location and density with respect to the perforation cluster location. We then tune key completion parameters using an in-house fracture propagation model to provide hydraulic fracture geometries that are constrained by the microseismic cloud. In the history matching process, we included the effect of natural fractures, using the microseismic events location as natural fracture initiation points. Finally, we used cutoff coefficients to further reduce hydraulic fracture geometries to match production data. The results of this work showed a fast and flexible method to estimate fracture half-lengths and fracture heights, resulting in a direct indicator of the completion design. Additionally, hydraulic-natural fracture interactions were assessed. We concluded that the inclusion of cutoff coefficients as history matching parameters allows to derive realistic hydraulic and natural fracture models calibrated with microseismic and production data in unconventional reservoirs.

The exploitation of unconventional reservoirs requires hydraulic fracturing treatments, aimed at enhancing reservoir rock permeability through the re-activation of existing natural micro-fractures and the generation of new fractures in the near-wellbore area. Microseismic Monitoring (MSM), which consists of acoustic recording of the induced fracturing events, has nowadays become a common approach for real-time tracking of the fracture network evolution. The present work is based on the analysis of microseismic and production data coming from three multi-fractured wells drilled in a shale gas reservoir. Information derived from MSM is integrated with the Advanced Production Analysis (APA) results, to assess if the MSM interpretations are able to provide preliminary indications about the production behavior of the fractured wells before start-up. The spatial localization of microseismic events and their moment magnitude are derived from the interpretation of the seismic signals recorded by geophones during hydraulic fracturing. Data analysis, based on the cross-plot of the event moment magnitude versus the distance between the event and the nearest geophone, allows the determination of the spatial range bias, i.e. the effect for which the level of the recorded magnitudes depends on the distance from the geophones. A novel methodology was developed to correct the spatial range bias by combing a Gaussian function and the Gutenberg-Richter law for fitting the Frequency Magnitude Distribution. After the correction, microseismic data from different wells and frac stages can be directly compared and used for the evaluation of the Stimulation Efficiency (SE) and the Stimulated Reservoir Volume (SRV). APA is used to analyze production data from the three selected wells in order to characterize both the fractured system and the reservoir. Even if the results obtained from MSM and APA techniques are often at different scales and not quantitatively comparable, it is still possible to obtain useful information from their integration. APA confirms, indeed, the interference between wells production due to the overlap of different SRV, as initially estimated from MSM interpretation. Thus, the results of the developed methodology allow to improve well placement, stimulation operation design and field development strategies.

Accurate modeling of hydrocarbon production is a necessary, yet challenging step for economic exploitation of unconventional resources. One of the main challenges is to model flow to a horizontal well from a complex network of hydraulic and natural fractures. Many unconventional reservoirs comprise well-developed natural fracture networks with multiple orientations and complex hydraulic fracture patterns based on microseismic data. Conventional dual porosity and dual permeability models are not adequate for modeling these complex networks of natural and hydraulic fractures. Also, it is neither practical nor advantageous to model a large number of pre-existing fractures with a discrete fracture model. Therefore, an appropriate approach to model production from low-permeability reservoirs is to perform discrete fracture modeling for hydraulic fractures and employ a dual continuum approach for numerous natural fractures. We have developed a coupled dual continuum and discrete fracture method to simulate production from unconventional oil and gas reservoirs. Large-scale hydraulic fractures (macro-fractures) are modeled explicitly using a discrete fracture model, called EDFM, and numerous small-scale natural fractures (micro-fractures) are modeled using a dual continuum approach. The hybrid model includes three domains: matrix, discrete-fracture, and continuum-fracture domains. A systematic approach is devised to calculate transport parameters between all three domains. Moreover, EDFM allows for not only transverse and longitudinal hydraulic fractures but also macro-fractures of any orientation. Thus, the coupled model provides an effective and reliable environment to improve stimulation designs and completion strategies. We present several examples in this study to show the applicability, robustness, and performance of the hybrid method for the simulation of unconventional oil and gas reservoirs. We examine multi-stage hydraulic fractures with multiple configurations in the presence of numerous pre-existing fractures. Simulations show a noticeable contribution from natural fracture networks on total production. Furthermore, for the tight oil reservoir examined in this study, the stimulation scheme with longer hydraulic fractures improves cumulative oil production compared to the scheme with larger number of shorter hydraulic fractures. We also examine production from a tight gas reservoir wherein hydraulic fractures partially penetrate the formation height. Simulations indicate that inefficient fracture treatment can result in significant loss of production.

The operator in West Africa embarked upon the "N" field offshore development in 2016 with 13 multi-stage horizontal wells being fracture-stimulated in Phase-I, with further wells being planned in next development phases. Due to the complex nature of the reservoir, which is a multilayered sandstone characterized by high heterogeneity and low permeability, wellbore connections are often located in structurally altered areas with high presence of faults. The unpredictable local re-orientation of the stresses has resulted in complications for the fracturing operations with multiple fractures being induced. This paper presents the challenges and solutions implemented for delivering more consistent fracturing execution and well productivity improvements. The horizontal wells in the "N" field were hydraulically fractured using the "plug-and-perf" method with up to four fractured intervals. The quality of the near-wellbore connection and the observations of complex near-wellbore fracture geometries have hindered far-field proppant distribution and limited maximum proppant concentration inside the fracture. When fracturing this tight formation, controlling the opening of the pressure-dependent multiple fractures was identified as a critical issue. An engineering breakdown process and adapted frac strategy was implemented to minimize the multiple fractures generated at the formation. For the early hydraulic fracture treatments performed, conservative treatment designs were applied in order to avoid premature screenout with the consequence of increasing operative time. Implemented solutions have shown to improve the near-wellbore connections and increase well productivity. The successful outcomes are attributed to the implementation of improved perforating strategies, the optimization of fracturing fluid performance, an engineered fracturing breakdown process, and the development of a frac decision tree for improved decision making. The hydraulic frac strategy has been tailored well-by-well depending on the reservoir conditions (e.g. faults, permeability thickness, contacts), and on the operational conditions interpreted from the diagnostic injection tests (e.g. near wellbore tortuosity, net pressure). The holistic implementation of these new concepts for hydraulic fracturing and field development have delivered positive production results beyond initial expectations. For the horizontal wells intersecting the deep low permeability "D" reservoir, the risk of multiple fractures and influence of tortuosity have been diminished through corrective techniques and unique solutions applied for each fracturing stage.

The past two decades have seen the development and expansion of an approach to wellbore completions that has resulted in unlocking significant reserves from previously disregarded resource, and has been responsible for the North American shale gas ‘revolution’ or ‘evolution’ (depending upon how you see it). However, this approach has faced significant complications to appropriate, successful and economic deployment, when attempts have been made to export this process overseas. This ground-breaking completion approach was achieved as a direct result of the combination of two well-known and widely applied industry technologies, from distinct disciplines: namely horizontal lateral drilling and propped hydraulic fracture stimulation. This simple combination is referred to by a number of different designations which are used to describe the process, but it is most commonly referred to simply as multi-stage horizontal well hydraulic fracturing. The North American success story has been primarily accomplished through the application of two distinct variants of this technique, split by fundamental approach to the stage sequencing: namely the Plug & Perf approach and the Open Hole Multi-Stage completion system (typically ball-activated fracture ports). The Open Hole Multi-Stage completion system has typically been applied selectively, with a bias towards clastic formations, whereas Plug & Perf has been more widely applied and almost exclusively dominates the shale completion environment. This paper will describe the engineering aspects of the multi-stage horizontal well hydraulic fracturing process, as well as those particular North America conditions and deliberate compromises that have been made, in order to encourage this approach to become established and develop further. Such analysis will include a holistic approach to the global market conditions, in order to better understand the local and regional factors that have played such a fundamental role in North American success, many of which have been erroneously overlooked elsewhere. This paper will investigate a number of these key issues and factors, particularly related to completion and reservoir interaction that should be considered carefully when choosing to export such techniques to new areas of application outside of North America. This will include an understanding of the key data that should be acquired, from the early exploration and subsequent appraisal wells, so that appropriate decisions can be made efficiently.

Microseismicity is a physical phenomenon which allows us to estimate the production capability of the well after hydraulic fracturing (HF) in a naturally fractured (NF) reservoir. Some of the microseismic events are reactivations of NFs induced by a direct hit of HF, while others are induced by the fluid leak-off from the previous stages or by elastic waves emitted into the reservoir with hydraulic fracture plane propagation. The former NFs have a chance to be propped there as the latter will not significantly increase their contribution to the production. Identification of such microseismic events helps to reduce uncertainty in the description of fracture network geometry. Based on inferred data from core analysis NF densities and orientations, we generated multiple realizations of the semi-stochastic Discrete Fracture Network (DFN). In order to constrain them, we used time evolution of microseismic cloud in addition to results of core analysis. Fluid and proppant pumping schedule is used to identify such microseismic events because they should be located close to the pressure diffusion front generated by hydraulic fluid. Events outside of proposed region may be triggered by other factors, such as stress-strain relaxation from other stages and correspondent fractures. In most cases, they are not wide enough to take proppant from the main HF. This approach was used to reduce range of production for DFN realizations. This workflow is implanted to a 15-stage hydraulic fracture treatment on a horizontal well placed in a siltstone reservoir with intrinsic fractures. The spatio-temporal dynamics of microseismic events are classified into two groups by the front of nonlinear pressure diffusion caused by 3-dimensional hydraulic fracturing, considered as effective and ineffective events. DFNs with only effective microseismicity and with all the induced events are generated. Then, two types of DFN related uncertainties on production are performed to evaluate the impact of filtration. Results of aleatory uncertainty quantification caused by the randomness of DFN modeling indicate the filtered events can generate a production DFN with a more consistent connected fracture area. Moreover, sensitivity analysis caused by lack of accuracy in natural fracture characterization shows the production area of DFN with filtration process is more insensitive to the variation of fracture parameters. Finally, a history match with production data and pressure data indicates this DFN model properly represents the reservoir and completion. Our methodology characterizes well the conductive fracture network utilizing core data, microseismic data, and pumping schedule. It could restore the true productivity of each fractured stage from a massive microseismic cloud, which helps understand the contribution of fracturing job right after the treatment.

This work presents new solutions to modeling the production performance of hydraulically fractured wells in unconventional reservoirs, where intensive hydraulic fracturing creates a stimulated reservoir volume (SRV) with an induced permeability field within.We found previously that the permeability field induced in the SRV (single porosity) can be effectively represented by an exponential or linear dependence of permeability on the distance measured from the main hydraulic fracture plane. However, many researchers consider dual porosity as a necessary ingredient in modeling unconventional reservoirs.In this work, we extend the induced permeability field model to the dual porosity idealization, considering transient fluid transfer from matrix to natural fractures and distance-dependent properties of the medium of secondary porosity (affected by the intensive stimulation).We show that the combined effect of creating a main fracture and altering the properties of the medium of secondary porosity leads to a production behavior that can be characterized and understood provided that effects related to skin and varying flowing bottomhole pressure are correctly accounted for.In addition to the standard diagnostic tools for decline-curve or rate-transient analysis, we use the ratio between the production time and material balance time, a dimensionless group that enables identifying the characteristic signatures of flow regimes. We provide practical criteria to identify various scenarios affecting the data during the pre-linear and prebilinear flow regimes in the reservoir (short times). Then we show that transient, late transient and boundary dominated flow periods can also be diagnosed using the dimensionless group, providing a useful addition to existing procedures involving conventional plots.In connection to the new model, this work also discusses a novel approach to handle non-constant bottomhole pressure, the cause of significant distortion in production data at early times. In particular, we consider the effect of a bottomhole pressure exponentially approaching a stabilized value. We show that the deviation from the idealized constant bottomhole pressure case depends on the flow regime in the reservoir, fluid and reservoir properties, skin factor, and the mean lifetime (the time when 63% of the total change has happened) of the decaying part of the flowing pressure. The results reveal that half-, three-fourths-, and unit-slope straight lines (on log-log plot of production rate versus time) develop at short times during the increasing trend of production rate. These new flow regimes enable to gain useful information about the SRV from the early stage of the production history – if the quality of data allows such a detailed analysis.We present a field example involving multi-fractured horizontal wells producing from a shale-gas reservoir, to illustrate, in a practical manner, how to apply the new approach when interpreting production history of wells in unconventional reservoirs.

The major factor influencing the increase of natural gas use is the rise in its global demand. Due to the relentlessly increasing demand, there have been improvements in the techniques and technology used in recovering natural gas from shale gas reservoirs, including drilling a horizontal well and hydraulic fracturing. One of the significant challenges associated with gas shale production is that it is difficult to reliably predict ultimate recovery and estimate reserves, leading to great risk in exploitation of these resources. The purpose of this research is to evaluate the current decline curve analysis techniques and provide a more reliable method for production forecast and reserve estimate for hydraulically fractured horizontal wells producing from gas shale reservoirs.;When production data of low permeability reservoirs are analyzed using Arp's equation, the decline exponent b which is supposed to range between 0 and 1 is usually greater than 1. The actual decline exponent b value is not easy to come by in the transient period during the life of the well, however, having a decline exponent b value greater than 1 will overestimate the remaining reserves of the well.;In this study, first, decline characteristics for shale gas wells are presented by simulating long-term production performance for a variety of well-reservoir systems, including Dimensionless fracture conductivity change, different fracture stages and fracture half-length; then different current decline analysis methods were evaluated in estimating reserves and predicting future performances. These methods are Conventional Decline Curve Analysis, the Backward Method and the Ilk Method. The evaluation task was done through quantitative comparison of production forecast results from current decline analysis with true simulated recovery.;Finally, the Backward & Ilk method was proposed and evaluated. This research work indicates that the Backward & Ilk method can provide the most suitable and accurate results in estimating reserves and analyzing production data.

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 131786, ’Integration of Microseismic and Other Post-Fracture Surveillance With Production Analysis: A Tight Gas Study,’ by C.R. Clarkson, SPE, University of Calgary, and J.J. Beierle, SPE, Talisman Energy, prepared for the 2010 SPE Unconventional Gas Conference, Pittsburgh, Pennsylvania, 23-25 February. The paper has not been peer reviewed. Quantitative production analysis of tight gas reservoirs is a challenge because of complex reservoir characteristics, induced-hydraulic-fracture properties in vertical wells, operational complexities, and data quality. These challenges make extracting reservoir and hydraulic-fracture properties (i.e., fracture half-length, xf, and fracture conductivity) solely from production and flowing-pressure data difficult, often resulting in nonunique answers. Many tight gas reservoirs are exploited with horizontal wells, often stimulated with multiple hydraulic fractures, imparting greater complexity to the analysis. Flow-regime identification, which is critical to correct analysis, becomes more complicated because of the variety of flow regimes that could be encountered in such wells. Introduction Development of tight gas, shale gas, and coalbed methane (collectively referred to as unconventional gas reservoirs) benefits from advances in drilling, completions, and stimulation technology; formation evaluation; and during-/post-stimulation-surveillance technology. Formation-evaluation techniques enable determining critical parameters such as matrix permeability in ultratight rock from cores, and adsorbed- and free-gas content in shale and coalbed methane from cores and cuttings. During-/post-fracture-stimulation-surveillance technology (such as microseismic monitoring) aids identifying the hydraulic-fracture geometry created in unconventional reservoirs (hydraulic-fracture growth), particularly in coals and shales. Predicting hydraulic-fracture geometries is complicated by heterogeneities, such as natural fractures (healed or open) and layering (with associated contrasts in mechanical properties), and in some cases, by nonlinear elastic behavior. Advanced production-analysis techniques, such as production type curves, supplement reservoir and stimulation information obtained from pressure-transient analysis (well testing) in conventional oil and gas reservoirs and even some unconventional reservoirs such as coalbed methane and tight gas. However, applying these methods to tight gas and shale reservoirs that are produced through multifractured horizontal wells has been difficult because of the complexity of the system, poor quality of flowing-pressure and rate data, and the lack of sufficient data to characterize the system fully. Even if the production and flowing-pressure data were of sufficient quality to identify flow regimes, as in pressure-transient analysis, without additional surveillance information, it is difficult to ascertain how the flow regimes relate to the reservoir and hydraulic-fracture system. If the flow regimes are misinterpreted, then the extracted information will be incorrect. A workflow is proposed to improve the quality of information extracted from production-data analysis (PDA) of hydraulically fractured horizontal wells completed in tight gas reservoirs.

One key limitation of conventional production data analysis (PDA) is non-uniqueness of solution. This can cause huge uncertainty in reservoir parameter estimates and hydrocarbon forecasts. Hence, there is need for an alternative approach to PDA. This paper tackles this issue using flowback data analysis (FDA) as a constraint to guide PDA. We recently extended the existing linear dual-porosity model (DPM) to develop a flowback analysis model (FAM). Here, we intend to i) test the accuracy of FAM to predict gas production in the field, and ii) investigate how the results from its application on flowback data could reduce the uncertainty associated with conventional PDA. This study applies FAM to history match 2-phase flowback data from three multifractured shale-gas wells completed in the Horn River Basin. The history match estimatesFAM estimates effective half-length and initial gas-volume in hydraulic-fractures before flowback. It is also used to forecasts post-flowback gas production. This forecast is verified by comparing it actual post-flowback production data. An independent single-phase PDA on post-flowback production data from the same shale-gas wells overestimates hydraulic fracture(HF) half-lengths compared to the FAM history-match results. This could be a result of the presence of water plugged secondary fractures with negligible communication interface with the hydraulic fractures during flowback. The interface significantly increases during post-flowback production periods as water gives way to gas from the matrix. One key result of this study is that HF half-lengths from PDA could significantly differ from those from post-flowback PDA. It is more appropriate to interpret both flowback and production data using a single multiphase model. FAM is an example of such models that captures the "necessary" physics for both flowback and production operations. PDA without considering flowback data could lead to inaccurate results. This study shows how to perform a robust flowback-data-analysis that complements PDA for comprehensive fracture/reservoir characterization. These results encourage the industry to start careful and accurate measurement of rate + pressure immediately after opening wells for flowback.