Tight Gas Formations Research Articles

Successful Applications of Pressure-Rate Deconvolution in the Cad-Nik Tight Gas Formations of the British Columbia Foothills

Summary The Cadomin-Nikanassin (Cad-Nik) sandstone formations in the Lower Cretaceous reservoirs along the reverse-thrust faulting belt of northeastern British Columbia (NEBC), Canada, have emerged in recent years as a new tight gas play. The low porosity (3?6%) of the rock matrix controls gas storativity, while the presence of natural fractures in the form of clusters or swarms allows significant and sustainable flow rates for commercial production. Newly drilled wells are commonly hydraulically fractured to establish or enhance wellbore connectivity to the natural-fracture network. Seismic mappings of these structural unconventional-gas reservoirs provide the early assessments of resource sizes and initial gas in place (IGIP), which usually bear large uncertainties because of the difficulty in determining reservoir structural closures and pay-porosity cutoffs. Regional analogue wells are often used to guide development decisions. Meanwhile, estimating connected reservoir volumes through conventional-gas material balances (p/z vs. cumulative production) and production-data analysis [rate-transient analysis (RTA)] has not been without challenges. Fairly long pressure buildups (PBUs), on the order of hundreds of hours, are often performed without seeing the pressure stabilization required to estimate accurately the reservoir pressure needed for material-balance calculations. The applicability of pressure extrapolation to these tests has not been systematically investigated; therefore, no reliable methods for using shorter shut-ins to estimate reservoir pressure currently exist. Thus, reliable average reservoir-pressure estimates require significantly longer well shut-in times in order to perform meaningful gas material balance. Because this is not practical, confidence in material-balance results requires a second, independent method for establishing connected well volumes to be used in comparisons and cross checking. One possible choice is RTA, but, in these fields, numerous times wellhead-pressure data are also unavailable or unreliable. This paper presents two field-case studies that demonstrate the successful application of the pressure/rate-deconvolution approach, combining a well?s long, high-quality production-rate history with accurate downhole-pressure data from relatively short buildup tests. This approach allows the reservoir engineer to (1) reconcile the performance-based estimated-ultimate-recovery estimates with the volumetric IGIPs; (2) establish, at the least, minimum well-drainage size and connected volume; and (3) select possible infill-drilling opportunities. A final benefit is that this often leads to a better understanding of well/reservoir parameters.

Production Analysis of Tight-Gas and Shale-Gas Reservoirs Using the Dynamic-Slippage Concept

Summary Shales and some tight-gas reservoirs have complex, multimodal pore-size distributions, including pore sizes in the nanopore range, causing gas to be transported by multiple flow mechanisms through the pore structure. Ertekin et al. (1986) developed a method to account for dual-mechanism (pressure- and concentration-driven) flow for tight formations that incorporated an apparent Klinkenberg gas-slippage factor that is not a constant, which is commonly assumed for tight gas reservoirs. In this work, we extend the dynamic-slippage concept to shale-gas reservoirs, for which it is postulated that multimechanism flow can occur. Inspired by recent studies that have demonstrated the complex pore structure of shale-gas reservoirs, which may include nanoporosity in kerogen, we first develop a numerical model that accounts for multimechanism flow in the inorganic- and organic-matter framework using the dynamic-slippage concept. In this formulation, unsteady-state desorption of gas from the kerogen is accounted for. We then generate a series of production forecasts using the numerical model to demonstrate the consequences of not rigorously accounting for multimechanism flow in tight formations. Finally, we modify modern rate-transient-analysis methods by altering pseudovariables to include dynamic-slippage and desorption effects and demonstrate the utility of this approach with simulated and field cases. The primary contribution of this work is therefore the demonstration of the use of modern rate-transient-analysis methods for reservoirs exhibiting multimechanism (non-Darcy) flow. The approach is considered to be useful for analysis of production data from shale-gas and tight-gas formations because it captures the physics of flow in such formations realistically.

Unconventional Job Hiring for Unconventional Resources Development

HR Discussion - Unconventional job hiring for unconventional resources development. Unconventional resources are those that were bypassed by conventional oil and gas recovery technologies for decades because they were not considered economically feasible to produce. Improvements since the early 1990s in geophysical and geochemical exploration and in drilling and completion technologies have opened up vast new resources both onshore and offshore. Some unconventional resources are in hostile or challenging environments such as the Arctic tundra or deep water. Others are in regions that have not previously experienced extensive oil and gas development and thus lack infrastructure and community and political support. Unconventional resources encompass tight oil and gas formations, shale gas, coalbed methane, heavy oil, oil shale, deep and ultradeepwater plays, and gas hydrates. Each of these types of play requires unique strategies and expertise to develop them. Hiring geoscientists and engineers for unconventional projects has never been more daunting. TWA ’s Human Resources (HR) Discussion Team had a roundtable discussion on unconventional resources, HR requirements, and career development strategy with two experts in unconventional resources development and resourcing—Mike Maneffa and George Alameda of Chevron.

Calculation of Irreducible Water Saturation (S wirr) from NMR Logs in Tight Gas Sands

It is difficult to calculate irreducible water saturation (S wirr) from nuclear magnetic resonance (NMR) logs in tight gas sands due to the effect of diffusion relaxation on the NMR T 2 spectrum at present. By combining with classical Timur and Schlumberger—Doll Research (SDR) models, a novel model of calculating S wirr is derived. The advantage of this novel model is that S wirr can be calculated without a T 2 cutoff, and all input information can be acquired from NMR logs accurately. With the calibration of 36 core samples, which were drilled from Xujiahe Formation in Bao-jie region of Triassic, Sichuan basin, southwest China, the values of these statistic model parameters are defined. Field examples of tight gas sands show that the proposed model is reliable. The S wirr calculated with the proposed model match well with core analyzed results both in tight gas formations and water-saturated layers, the absolute error is in the range of ±4%. The calculated results by using 20.75 ms as the T 2 cutoff are accurate in water-saturated layers but are overestimated in gas-bearing intervals. Defining 33 ms as the T 2 cutoff is unusable both in gas-bearing and water layers.

Channel Fracturing - Paradigm Shift in Tight Gas Stimulation

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 140549, ’Channel Fracturing - A Paradigm Shift in Tight Gas Stimulation,’ by J. Johnson, SPE, M. Turner, SPE, and C. Weinstock, SPE, Encana; and A. Pena, SPE, M. Laggan, SPE, J. Rondon, and K. Lyapunov, Schlumberger, prepared for the 2011 SPE Hydraulic Fracturing Technology Conference and Exhibition, The Woodlands, Texas, 24-26 January. The paper has not been peer reviewed. The hydraulic-channel-fracturing technique relies on the engineered creation of a network of open channels within the proppant pack, providing highly conductive paths for fluid flowing from the reservoir to the wellbore. The Lance formation in the Jonah field near Pinedale, Wyoming, was selected for this study. Results indicate that implementation of the channel-fracturing technique increased initial gas production and estimated recovery over conventional fracturing methods. Positive features during this campaign included reduced net-pressure-increase estimates from pre- and post-fracture-treatment shut-in-pressure measurements, reduced tendency for vertical fracture growth, and elimination of near-wellbore screenouts. Introduction Natural gas plays a major role in the assortment of energy resources that sustain the USA. The imbalance between future energy demands and reduced availability of gas from conventional sources dictates the need to increase gas recovery from unconventional sources such as tight gas reservoirs, shale-gas reservoirs, and coal seams. Hydraulic-fracturing treatments in tight gas formations during the 1970s consisted of pumping large quantities of a propping agent and carrying gelled fluids and emulsions at pressures in excess of the formation-fracturing pressure. Beginning in the 1980s, this fracturing technique included various combinations of nitrogen gas and/or liquid carbon dioxide pumped in combination with fluid and proppant for stimulation purposes. Low-viscosity slickwater treatments, in which proppant is pumped at low concentrations within a high-rate water stream, became popular in the 1990s for stimulating tight gas reservoirs. All these techniques rely on filling the fracture with the propping agent to maintain an open fracture. The proppant pack placed within the fracture also serves as a conductive medium for gas flow to reach the wellbore. The effective area of the fracture covered by proppant varies according to the technique used. Typically, completion efficiency is low for slickwater treatments, and it often improves with the use of viscous carrying fluids and fibers, among other methods.

Defining Horizontal-Well Objectives in Unconventional and Tight Gas Reservoirs

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 137839, ’Defining Horizontal-Well Objectives in Tight and Unconventional Gas Reservoirs,’ by L.K. Britt, SPE, J.R. Jones, SPE, and W.K. Miller II, SPE, NSI Fracturing, prepared for the 2010 Canadian Unconventional Resources & International Petroleum Conference, Calgary, 19-21 October. The paper has not been peer reviewed. Because unconventional and tight-formation gas reservoirs have poorer-quality pay, a well-planned completion and fracture-stimulation program is required to obtain an economical well. Economic-optimization studies for tight gas reservoirs highlight the importance of lateral length, number of fractures, interfracture distance, fracture half-length, and fracture conductivity. A horizontal-well decision tree was developed for evaluating the various drilling, completion, and stimulation issues encountered with horizontal wells in unconventional and tight-formation gas reservoirs. Introduction Operators have reported difficulty in fracture stimulating some deviated and horizontal wells. The difficulties are associated with increased treating pressures and elevated post-fracture instantaneous shut-in pressures. In unconventional and tight-formation gas reservoirs, greater operational control and reliability are necessary to maintain project economics. Optimization studies of these reservoirs showed the importance and value of integrating horizontal drilling, completion, and well-stimulation practices. To understand the horizontal-well objectives in these reservoirs, a simulation study was undertaken, and the economics of multiple-fractured horizontal wells in tight gas reservoirs was investigated. Of interest in this evaluation were reservoir, completion, and stimulation parameters. Net pay, reservoir pressure, and reservoir permeability were evaluated. For the completion practices, completion control was considered; and for fracture stimulation, the effects of fracture length and conductivity were considered in light of fractured-horizontal-well objectives. Finally, horizontal-well drilling, completion, and fracture-stimulation costs were considered along with economic parameters to ensure that the horizontal-well objectives were established for all environments. Recoverable-Reserves Considerations The study compared reservoirs with 25, 50, and 100 ft of net pay. For a reservoir with limited net pay (25 ft), the optimal number of completions and fracture stimulations required to deplete the reservoir was five. Beyond five, there was little to no economic benefit from increasing the number of fractures. For a reservoir with 50 and 100 ft of net-pay thickness, the economically optimum number of completions was nine and 20, respectively. Thus, the greater the amount of recoverable gas, the more completions that are needed to recover those reserves optimally. Also, doubling the net pay in this example tripled the economic value, and quadrupling the net pay to 100 ft resulted in an eight-fold increase in the discounted net present value. Instantaneous potential (IP), or 30-day rate, for these three cases from 25 to 100 ft of net pay increased linearly with the number of fractures, up to 15 completions/fractures. However, beyond 15, the IP was not linear, indicating that the fractures were interfering with each other within 30 days.

Cumulative-Gas-Production Distribution on the Nikanassin Tight Gas Formation, Alberta and British Columbia, Canada

Summary271 wells producing exclusively from the Nikanassin and equivalent formations in a very large area of more than 15,000 km2 in the Western Canada Sedimentary basin (WCSB), Alberta and British Columbia, Canada, have been evaluated with a view to determine the distribution of cumulative gas production and the possibilities of intensive infill drilling.The Upper Jurassic to Lower Cretaceous Nikanassin formation is generally characterized as a tight gas formation with low values of permeability (typically a fraction of millidarcy) and low porosities (usually less than 6%). It is likely that natural microfractures and slot pores dominate the productivity of the formation. The study area was divided into six smaller narrow areas (A through F) approximately parallel to the northwest/southeast-trending thrust belt of the Canadian Rocky Mountains. Area A is located to the west of the deformation edge, Area B is on the deformation edge, and Areas C through F are located to the east. Area C is the deepest and closest to the thrust belt, whereas Area F is the shallowest and farthest from the thrust belt.Cumulative production characteristics within each area were evaluated with a variability distribution model (VDM) developed recently for naturally fractured reservoirs. The evaluation of each one of the six areas (271 wells) resulted in coefficients of determination, R2 greater than 0.99 in all cases. The results indicate that the gas cumulative production distribution per well is more homogeneous along the deformation edge (Area B), in which 80% of the wells contribute approximately 50% of the cumulative production. The highest heterogeneity was found in Area F (the shallowest), with 80% of the wells contributing only 25% of the cumulative gas production. Areas A, C, D, and E have more or less the same distribution with 80% of the wells contributing between 35 and 45% of the cumulative gas production. In preliminary terms, there is an association between the cumulative-production distribution and lateral variations of borehole breakouts in the Nikanassin formation on a transect perpendicular to the deformation belt of the WCSB.Analysis of the distributions leads to the conclusion that the Nikanassin is a very heterogeneous formation and that there is significant potential for massive drilling to efficiently drain the formation. The possibilities of horizontal wells and multistage hydraulic-fracturing jobs are being investigated at this time.

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

Quantitative production analysis of tight gas reservoirs has historically been a challenge due to complex reservoir characteristics (ex. lateral and vertical heterogeneity, stress-sensitivity of permeability and porosity), induced hydraulic fracture properties in vertical wells (ex. multi-phase flow, conductivity changes, complex fracture geometries), operational complexities (ex. variable back-pressure, liquid-loading) and data quality (infrequent rate or flowing pressure reporting). All of these challenges conspire to make extraction of reservoir ( kh and OGIP) and hydraulic fracture properties ( x f and fracture conductivity) soley from production/flowing pressure data difficult, often resulting in non-unique answers. In recent history, there has been the added complication that tight gas (and most recently shale gas) reservoirs are now being exploited with horizontal wells, often stimulated using multiple hydraulic fracture stages, which imparts greater complexity on the analysis. Flow regime identification, which is critical to the correct analysis, is more complicated than ever owing to the number of possible flow regimes encountered in such wells. A case study is presented in which it is demonstrated that modern post-fracture surveillance data, such as microseismic and post-frac production logging, aids in both model identification and model calibration, which is critical to the analysis of hydraulically-fractured horizontal wells completed in tight gas formations. A workflow is presented in which offset vertical wells (to the horizontal wells) are first analyzed to obtain estimates of kh and hydraulic fracture properties, followed by commingled stage and single-stage production analysis of the multi- (transverse) hydraulic fracture horizontal wells. Microseismic data is incorporated into the analysis of the horizontal wells to 1) understand the orientation and degree of complexity of the induced hydraulic fractures and 2) constrain interpretations of effective hydraulic fracture lengths from production data analysis. It is also demonstrated that once the commingled stage analysis of the horizontal wells is completed, the total interpreted effective hydraulic fracture half-length may be allocated amongst the stages using a combination of production logs and tracer logs. The primary contribution of the current work is the presentation of workflows, emphasizing the integration of various data sources, to improve production analysis of multi-frac’d horizontal wells completed in tight gas formations. In addition to the workflows, it is shown that a combination of advanced production analysis approaches, including methods analogous to classic pressure transient analysis, production type-curve matching and simulation, may be necessary to arrive at a unique analysis.

Investigation of Effect of Fracturing Fluid on After-Closure Analysis in Gas Reservoirs

Summary Published techniques for analysis of after-closure fracture data usually assume single-phase flow. These procedures generally rely on the techniques developed for the analysis of buildup tests. Applying the buildup techniques implies that the injected fluid and reservoir fluid have approximately the same properties. This assumption is generally incorrect in case of minifrac tests where the injected fluid may be very different from the reservoir fluids. This situation is at an extreme when the minifrac test is conducted on a gas reservoir and the injected fluid may be a relatively high-viscosity gelled fluid. In this paper, we review the basic theory behind after-closure analysis. Using a numerical simulator, minifrac tests are simulated and analyzed for both oil- and gas-reservoir cases where an aqueous phase is injected as a fracturing fluid. Analyses of the numerically simulated falloff data are presented. Guidelines for the analysis of such data have been developed and presented. Field data are also presented. In one case, breakdown, step-rate, and fluid-efficiency tests (FETs) were performed on a tight gas formation and the data were analyzed. The results of using these various techniques are presented. The consistency of results validates conclusions achieved using the numerically simulated data.

Petrophysical and capillary pressure properties of the upper Triassic Xujiahe Formation tight gas sandstones in western Sichuan, China

The tight sandstones of the Upper Triassic Xujiahe Formation (T3x) constitute important gas reservoirs in western Sichuan. The Xujiahe sandstones are characterized by low to very low porosity (av. 5.22% and 3.62% for the T3x4 and T3x2 sandstones, respectively), extremely low permeability (av. 0.060 mD and 0.058 mD for the T3x4 and T3x2 sandstones, respectively), strong heterogeneity, micronano pore throat, and poor pore throat sorting. As a result of complex pore structure and the occurrence of fractures, weak correlations exist between petrophysical properties and pore throat size, demonstrating that porosity or pore throat size alone does not serve as a good permeability predictor. Much improved correlations can be obtained between permeability and porosity when pore throat radii are incorporated. Correlations between porosity, permeability, and pore throat radii corresponding to different saturations of mercury were established, showing that the pore throat radius at 20% mercury saturation (R20) is the best permeability predictor. Multivariate regression analysis and artificial neural network (ANN) methods were used to establish permeability prediction models and the unique characteristics of neural networks enable them to be more successful in predicting permeability than the multivariate regression model. In addition, four petrophysical rock types can be identified based on the distributions of R20, each exhibiting distinct petrophysical properties and corresponding to different flow units.

Evaluation of damage mechanisms and skin factor in tight gas reservoirs

Tight gas reservoirs normally have production problems due to very low matrix permeability and significant damage during well drilling, completion, stimulation and production. Therefore, they may not flow gas at optimum rates without advanced production improvement techniques. The main damage mechanisms and the factors that have significant influence on total skin factor in tight gas reservoirs include: mechanical damage to formation rock; plugging of natural fractures by mud solid particle invasion; relative permeability reduction around wellbore as a result of filtrate invasion; liquid leak-off into the formation during fracturing operations; water blocking; skin due to wellbore breakouts; and the damage associated with perforation. Drilling and fracturing fluids invasion mostly occurs through natural fractures and may also lead to serious permeability reduction in the rock matrix that surrounds the natural or hydraulic fractures. This study represents an evaluation of different damage mechanisms in tight gas formations, and examines the factors that can have significant influence on total skin factor and well productivity. Reservoir simulation was carried out based on a typical West Australian tight gas reservoir to understand how well productivity is affected by each of the damage mechanisms, such as natural fracture plugging, mud filtrate invasion, water blocking and perforation. Furthermore, some damage prevention and productivity improvement techniques are proposed, which can help improve well productivity in tight gas reservoirs.

An Evaluation of Microseismic Monitoring of Lenticular Tight-Sandstone Stimulations

SummaryMicroseismic monitoring in lenticular tight gas formations has a number of challenging issues associated with both analysis and interpretation. The heterogeneous nature of the reservoir and the typically small microseismic-event amplitudes make it essential to understand the limits of interpretation that should be applied in these reservoirs. With proper care, fracture lengths and azimuth, along with zonal coverage, are readily obtainable. However, fracture-height growth in these complex reservoirs needs to be assessed carefully. Microseismic data provide a level of self-quality-control potential through the use of a magnitude/distance assessment to guide interpretation and design. Hydraulic fractures observed in these reservoirs tend to be long, penetrating fractures that wander through the distributed/sand lenses, with modest height growth in most projects.

A Method for Estimating Hydrocarbon Cumulative Production Distribution of Individual Wells in Naturally Fractured Carbonates, Sandstones, Shale Gas, Coalbed Methane and Tight Gas Formations

Summary A method, based on factual observations of naturally fractured reservoirs in several countries, is presented for estimating distribution of hydrocarbon cumulative production in wells drilled in fractured reservoirs of Types A, B or C. These observations indicate that in reservoirs of Type C, most of the cumulative production is provided by just a few wells, while the majority of the wells contribute a small part of the reservoir cumulative production. In reservoirs of Type B, the number of wells contributing significantly to cumulative production becomes larger relative to the case of Type C reservoirs. Finally, in reservoirs of Type A, a large number of wells contribute to field production, as compared with Type B reservoirs. The method is shown to be useful for tackling problems of practical importance in naturally fractured reservoirs, including performing or not performing infill drilling, estimating the variation in cumulative hydrocarbon production per well in a given reservoir and estimating the number of wells that might be required for a given field hydrocarbon recovery. The method is illustrated using data from various fractured reservoirs, including the Barnett shale and sandstone reservoirs in the United States, carbonate reservoirs in Mexico and Venezuela and coalbed methane reservoirs and tight gas sands in Canada.

Analyzing, Optimizing Frac Treatments By Means of a Numerical Simulator

Technology Update Hydraulic fracturing and refracturing has become an integral part of completing wells, especially in unconventional reservoirs such as tight gas formations, shale, coalbed methane, and tight oil reservoirs. Practicing reservoir and production engineers now require access to a well-completion simulator. This completion simulator should have the ability to simulate productivity of complex reservoirs and wells, not only to design an optimum fracturing treatment but also to analyze production results. For a practicing engineer, the prediction of productivity of fractured wells requires a balance between accurate representation of the physical process of reservoir fluid flow and the time required to simulate that process. Because unconventional reservoirs and associated wells can be complex, analytical solutions are usually not capable of providing an adequate prediction of the well performance. The need for a comprehensive, yet easily accessible, numerical simulator for well-completion processes has become a necessity. The basic philosophy behind such a simulator is that it would Emphasize prediction of a small number of wells, including the capability of predicting single-well production and performing related analysis. Provide higher speed in both simulation and turnaround rate. This goal can be achieved through the use of a graphical user interface. Some of the more complex features may be accessible to more sophisticated users by means of special file handling to enhance analysis capability. Automate the simulation of specialized features that may be crucial to stimulation. These features include the following: Consideration of the fracturing-fluid filtrate as a separate aqueous fluid Linkage to a commercially available proppant library Ability to import fracture geometry and properties, including proppant concentration and type, fracture width, and amount of fluid leakoff into the formation for each fracture grid from commercially available fracture-design simulators—specifically, the 3D design programs StimPlan (NSI Technologies) and GOHFER (Barree and Associates)

In-Situ Water-Blocking Measurements and Interpretation Related to Fracturing Operations in Tight Gas Reservoirs

Summary Invasion of aqueous drilling, completion, or fracturing fluids can reduce the relative permeability to gas and thereby causes a water block. In the case of low-permeability formations, the capillary pressure tends to be high because of the small pore size. Cleanup of water blocks requires high drawdown unless water vaporization by the flowing gas is improved by using specific additives such as alcohols. The purpose of this work is to investigate fracture-face damage by measuring relevant petrophysical parameters: absolute-permeability damage and gas return permeabilities. Measurements are performed in representative conditions of a fracturing operation in a tight gas formation: cores with an absolute permeability of 10 μd set at Swi and experimental pressure of 200 bars for the fracturing-fluid invasion. Water and gas saturations during the fracturing-fluid invasion and during gas backflow are monitored by X-ray equipment. Adding alcohol in the fracturing fluid has a striking effect on resolving water blocks. Cake formation on the simulated fracture face is also discussed. Numerical simulations are performed to assess relative permeabilities from the experimental results. It is shown that hysteresis of gas and water relative permeabilities has a strong impact on the rate of water removal. Sufficiently high pressure drawdown is crucial to overcome capillary forces and initiate the alcohol- assisted vaporization process. Water removal by water vaporization is assessed and compared to the experimental results.

Simulation of hydraulic fracturing in tight formations

Production from tight formations is becoming a main focus around the world and particularly in Australia. Hydraulic fracturing is one of the commonly used approaches to stimulate production from tight reservoirs. A good understanding of mechanical properties of formation and the in-situ stresses is essential for a hydraulic fracturing study. In this work, using the log based approach, the mechanical properties and in-situ stresses were estimated in a tight gas formation. This data is then used as input for 2D numerical simulation of hydraulic fracturing in particle flow code (PFC). The initiation and propagation of an induced fracture was studied by increasing the rock strength to simulate a tight formation response. Thereafter, the model was divided into two zones to investigate the fracture containment capacity to simulate a fracture intersecting an interbed with formation properties being different on the two sides. The formation bond strength was increased on one side of the interbed and fracture extension was monitored. The results of both simulations showed how, by increasing formation strength equivalent to a tighter formation, the fracture extension ability reduces and the interbed containment capacity increases. The results were compared with some of the analytical models and good agreement was observed.

Liquid loading in wellbores and its effect on cleanup period and well productivity in tight gas sand reservoirs

Tight gas reservoirs normally have production problems due to very low matrix permeability and significant damage during well drilling, completion, stimulation and production. Therefore they might not flow gas to surface at optimum rates without advanced production improvement techniques. After well stimulation and fracturing operations, invaded liquids such as filtrate will flow from the reservoir into the wellbore, as gas is produced during well cleanup. In addition, there might be production of condensate with gas. The produced liquids when loaded and re-circulated downhole in wellbores, can significantly reduce the gas production rate and well productivity in tight gas formations. This paper presents assessments of tight gas reservoir productivity issues related to liquid loading in wellbores using numerical simulation of multiphase flow in deviated and horizontal wells. A field example of production logging in a horizontal well is used to verify reliability of the numerical simulation model outputs. Well production performance modelling is also performed to quantitatively evaluate water loading in a typical tight gas well, and test the water unloading techniques that can improve the well productivity. The results indicate the effect of downhole liquid loading on well productivity in tight gas reservoirs. It also shows how well cleanup is sped up with the improved well productivity when downhole circulating liquids are lifted using the proposed methods.

Characterization of Hydraulically Induced Fracture Network in a Tight Gas Formation Using Treatment and Microseismic Data

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 125237, "Characterization of Hydraulically Induced Fracture Network Using Treatment and Microseismic Data in a Tight Gas Formation: A Geomechanical Approach," by Wenyue Xu, Joël Le Calvez, and Marc Thiercelin, Schlumberger, prepared for the 2009 SPE Tight Gas Completions Conference, San Antonio, Texas, 15-17 June. The paper has not been peer reviewed. Large amounts of gas are produced from unconventional tight-gas-sand reservoirs (e.g., Cotton Valley, Lobo, Taylor Sand, and Wilcox formations) and gas-bearing shale formations (e.g., Barnett, Fayetteville, Marcellus, and Woodford). These plays are driven partly by technology and partly by economics. Modern well-log-evaluation techniques and completion methods are required to yield economical wells. In some cases, microseismic-monitoring campaigns are performed in these low-permeability environments to improve the understanding of the induced-fracture network and to go beyond the simple assumption of a symmetric biwing-fracture system. Introduction Use of traditional models, assuming single- or biwing-type induced fractures, has produced successful hydraulic fracturing in conventional reservoirs. However, these models cannot represent the complex nature of induced fractures in unconventional reservoirs with pre-existing fractures. The otherwise straightforward propagation of a simple wing-like hydraulic fracture tends to interact with nearby pre-existing natural fractures. There are indications of microseismic activity being related to stress effects and to actual fluid movement. In some cases, a volumetric hydraulic-fracturing process is indicated. Recent efforts have been made to map the pattern of induced-fracture networks on the basis of observed microseismic-event distribution. These interpretations were not constrained closely by accounting for the amount of pumped fluid and mechanical interactions between fracture and injected fluid as well as among nearby fractures. Fracture-Network Model To characterize the induced-fracture network better, a semianalytical pseudo-3D geomechanical model was developed on the basis of the conservation of injected-fluid mass and mechanical interactions between fractures and injected fluid as well as among the fractures. The hydraulically stimulated volume is represented by a horizontally expanding ellipse containing a simplified fracture network consisting of two sets of vertical planar fractures perpendicular to one another. This model provides a mathematically equivalent description of the process of hydraulic-fracture propagation and the characteristics of the induced fractures.

Effect of Fracture Dip on Petrophysical Evaluation of Naturally Fractured Reservoirs

Abstract Recent models show the means of estimating the petrophysical porosity exponent (m) of a reservoir when it is composed of different combinations of matrix, fractures and vugs. For both dual and triple porosity reservoirs, the system is modelled as a parallel resistance network (for matrix and fractures), a series resistance network (for matrix and non-connected vugs) or a combination of parallel/series resistance networks (for matrix, fractures and non-connected vugs). In the case of matrix/fractures, it has been assumed that the flow of the current is parallel to the fractures. This paper shows the effect on m of current flow that is not parallel to the fractures. This type of anisotropy is co-relatable with fracture dip. Maxwell Garnett mixing formula for calculating effective permittivity of a system with aligned ellipsoids and depolarization factors of 0 and 1 leads to the parallel and series resistance networks used in the paper. It is concluded that the change in fracture dip can have a significant effect on the value of m. Not taking this into account can lead, in some cases, to significant errors. The effect of the change of fracture dip on water saturation calculations is illustrated using two examples. Introduction The petrophysical analysis of fractured and vuggy reservoirs has been an area of abundant interest in the oil and gas industry. For example, a key ingredient for successful completion of wells in naturally fractured tight gas formations is the ability to distinguish gas from water-bearing intervals. Proper estimates of petrophysical parameters, including the porosity or cementation exponent m, play an important role in correct estimations of watersaturation (Sw). Towle(1) gave consideration to some assumed pore geometries, as well as tortuosity, and noticed a variation in the porosity exponent m in Archie's(2) equation ranging from 2.67 to 7.3+ for vuggy reservoirs and values much smaller than 2 for fractured reservoirs. Matrix porosity in Towle's models was equal to zero. Aguilera(3) introduced a dual porosity model capable of handling matrix and fracture porosity. That research considered three different values of the porosity exponent: one for the matrix (mb), one for the fractures (mf = 1) and one for the composite system (m). It was found that as the amount of fracturing increased, the value of m became smaller. Rasmus(4) and Draxler and Edwards(5) presented dual porosity models that included potential changes in fracture tortuosity and the porosity exponent (mf) of the fractures. The models are useful, but must be used carefully as they calculate values of m > mb as the total porosity increases, even when the flow of current goes parallel to the fractures. Serra(6) developed a graph of the porosity exponent (m) versus total porosity for both fractured reservoirs and reservoirs with non-connected vugs. The graph is useful, but must be employed carefully as it can lead to errors for certain combinations of matrix and non-connected vug porosities(7). The main problem with the graph is that Serra's matrix porosity is attached to the bulk volume of the 'composite system.'

Fracture Impact of Yield Stress and Fracture-Face Damage on Production With a Three-Phase 2D Model

Summary The fracture-propagation process performed with polymer-based fracturing fluids is applied commonly to increase the productivity of producing wells, especially in tight gas formations. The fracture-cleanup process is complex and may suffer from the presence of a yield stress, non-Newtonian fluid in place, and both mechanical and hydraulic damage to the matrix near the fracture face. A previously published fast-and-robust single-well model was applied to study the important parameters involved in the fracture-cleanup process. This three-phase 2D model proved useful for assessing the significance of reservoir capillary pressure, broken-gel viscosity, yield stress, formation damage, and fracture conductivity on low-permeability-gas-reservoir production, with studied permeabilities ranging from 0.005 to 5 md. The observed trends may not carry over to nanodarcy reservoirs, such as the gas shales. The three phases included gas, water, and fracturing gel. Introduction Hydraulic fracturing has been used as a successful technology to increase productivity by means of significantly increased contact between the wellbore and the producing formation. To propagate an open fracture into a reservoir, fracturing fluids have been used to provide the two main functions of initiating and propagating the fracture and transporting propping agents along the fracture. Guar gum is the earliest example of an aqueous, viscous fluid used during the injection. The fracturing fluid must be viscous to allow the transport of the proppant during the injection, and it must have the ability to be broken easily after the injection to maintain high conductivity in the fracture during the production phase. To accomplish these tasks, crosslinkers (such as borates and zirconates) and delayed breakers (either oxidizers or enzymes) are added typically to the fluid (Economides and Nolte 2000). Injection of the viscous fracturing fluid results in fluid loss to the matrix and filter-cake formation. Filter cakes with high polymer concentration form on the faces of the fracture during the injection. Original fracturing fluid may remain in the fracture unless the fracture-face filter cake occupies the entire pore space of the propped fracture following closure (Ayoub et al. 2006). Varying exposure times to fracturing fluid (Seright 2002) cause local polymer-concentration changes along the fracture. Thus, breakers are seldom distributed uniformly, and the break of the concentrated fluid is seldom complete. At the end of a fracture treatment, there is normally a shut-in period to allow fracture closure during which fluid continues to leak off into the reservoir. Alternatively, and especially for tight gas reservoirs, the fracture can be forced to close by flowing back some of the fracturing fluid at controlled rates to prevent disturbing the proppant pack significantly. As a result, hydraulic fractures contain partially broken fracturing fluid, and residues remain after the breaker reacts with the polymer. It has been postulated that fracturing fluids need a minimum pressure gradient to begin the cleanup process in the proppant pack (May et al. 1997), and this has been verified experimentally (Ayoub et al. 2006). The fracturing process, depending upon reservoir-matrix permeability, can cause mechanical damage through various mechanisms including fluid invasion into the reservoir, polymer-solids deposition near the fracture face as filter cake forms, clay swelling in the case of incompatible fluids, broken-polymer/fines migration into the reservoir matrix, and chemical interactions between the fracturing fluid and the matrix such as pH alteration or polymer adsorption (Holditch 1979). In addition, hydraulic damage occurs from the increase in water saturation caused by leakoff. The hydraulic damage can include a reduction in gas relative permeability and relative permeability hysteresis in the matrix where fracturing fluid has leaked off as the water saturation is first increased during leakoff and then decreased during the production phase. A shift in the capillary pressure curve to higher values can also result from mechanical damage. The production process becomes even more complicated in tight gas formations with permeability less than 0.1 md when the combined effects of closure stress, non-Darcy flow, high capillary pressure in the matrix, and viscous fingering in the proppant pack cause additional issues and restrict the production rate. The objectives of this study were to develop a basic understanding of the major factors impacting the fracture-cleanup process in tight gas formations with permeability of 0.005 md or greater, including yield stress of the filter cake, capillary pressure changes, and formation damage, by use of available numerical models. A three-phase, 2D model reported in the literature (Friedel 2004) was used for this study.