Summary Long-term transient linear flow of hydraulically fractured vertical and horizontal wells completed in tight/shale gas wells has historically been analyzed by use of the square-root-of-time plot. Pseudovariables are typically used for compressible fluids to account for pressure-dependence of fluid properties. Recently, a corrected pseudotime has been introduced for this purpose, in which the average pressure in the distance of investigation (DOI) is calculated with an appropriate material-balance equation. The DOI calculation is therefore a key component in the determination of the linear-flow parameter (product of fracture half-length and square root of permeability, x f k ) and the calculation of contacted fluid in place. Until now, the DOI for transient linear flow has been determined empirically, and may not be accurate for all combinations of fluid properties and operating conditions. In this work, we have derived the DOI equations analytically for transient linear flow under constant-flowing-pressure and -rate conditions. For the first time, rigorous methodologies have been used for this purpose. Two different approaches were used: the maximum rate of pressure response (impulse concept) and the transient/boundary-dominated flow intersection method. The two approaches resulted in constants in the DOI equation that are much different from previously derived versions for the constant-flowing-pressure case. The accuracy of the new equations was tested by analyzing synthetic production data from a series of fine-grid numerical simulations. Single-phase oil and gas cases were analyzed; pseudovariable alteration for pressure-dependent porosity and permeability was required in the analysis. The calculated linear-flow parameters, determined from our new DOI formulations for the constant-flowing-bottomhole-pressure (FBHP) case, and the input values to numerical simulation, are in good agreement. Of the two new DOI-calculation methods provided, the maximum rate of pressure response (unit impulse method) provides more accurate results. Finally, a field case was analyzed to determine the impact of DOI formulations on derivations of the linear-flow parameter from field data. Linear-flow analysis on the basis of the DOI calculations presented in this work is significantly improved over previous formulations for constant FBHP.

Summary There is now an array of analytical, semianalytical, and empirical forecasting methods that can be used to history match and forecast multifractured horizontal wells (MFHWs) completed in low-permeability (tight) reservoirs. Recent developments in analytical modelling have extended model application to cases in which the fracture geometry associated with MFHWs is complex. However, analytical modelling is still primarily limited to single-phase-flow problems, which is very restrictive, and potentially inaccurate, for tight oil and liquid-rich gas reservoirs flowing at less than saturation pressure. In this work, a semianalytical method is presented for history matching and forecasting MFHWs with simple and complex fracture geometry completed in tight, black-oil reservoirs and flowing at less than the bubblepoint pressure. The linear-to-boundary (LTB) model, commonly used to model flow in the inner (stimulated) region of an MFHW, is altered to account for two-phase flow of oil and gas. The enhanced-fracture-region (EFR) case, in which both stimulated and nonstimulated regions contribute to flow, is approximated (empirically) by superposition of two modified LTB models (one representing the inner fractured region and the other the outer, nonstimulated region), and similarly altered to account for two-phase flow. An important observation is that, for MFHWs flowing at less than bubblepoint at constant flowing bottomhole pressure during transient linear flow, the slope of the square-root-of-time plot for both oil and gas phases is constant [i.e., gas/oil ratio (GOR) is constant]. The slope and intercept of the square-root-of-time plot for the primary phase (e.g., oil in the cases studied) can therefore be used to generate a forecast during the transient linear-flow period for oil and for gas (by assuming constant GOR). For boundary-dominated flow, a robust method for forecasting gas and oil was developed using material balance for both phases combined with a modified productivity-index equation that accounts for multiphase flow. A fully implicit approach has been used to solve the flow equations for oil and gas. The new modified LTB and EFR models simplify forecasting considerably for low-permeability black-oil reservoirs exhibiting multiphase flow behaviour, relative to numerical simulation, although they are not as rigorous. The new models can, however, be tied directly to the results of rate-transient analysis and are flexible enough to be applied to common conceptual models used in the literature for forecasting MFHWs under certain conditions. The new modified LTB model has been compared with both simulated and field examples. The initial results demonstrate that transient- and boundary-dominated-flow periods for oil and gas are reasonably matched with the new approach, although slight mismatches may occur, particularly during early boundary-dominated flow. The limits of the new forecasting method will continue to be explored in future work.

Because of the Alberta Energy Regulator's minifractures test requirements on thermal or polymer-injection projects as part of the licensing process, a pressure-transient-analysis (PTA) based interpretation approach using field minifracture data can reduce the ambiguities and incorrect interpretations brought on by traditional approaches. Understanding that maximum operating injection pressure for injection wells has a significant impact on the economics of any given project, the study highlighted in this paper establishes a physics-based interpretation method that covers all injection/falloff minifracture tests.

This study provides methods that can be simply applied to constrain forecasts and improve accuracy for forecasting a large number of liquid-rich shale wells. Using simulation cases, the authors demonstrate that constant condensate/gas ratios (CGRs) can occur for tight/shale gas/condensate wells exhibiting transient linear flow and flowing at near-constant flowing bottomehole pressure and that single-phase forecasting methods can be applied, even if multiphase flow is occuring in the reservoir.

Caprock-integrity issues have been brought to the forefront with recent documented steam and bitumen leaks making their way to the ground surface, forcing the Alberta Energy Regulator (AER) to place a moratorium on the licensing of shallow thermal in-situ oil-sand projects. Reviewing core-acquisition, -storage, -analysis, and -preservation techniques can prevent potential project failure, capital loss, environmental liabilities, and public-safety risks. Responsible development of thermal projects requires that caprock integrity be quantified.

Research from this paper provides insight into the physical and chemical consequences of steam-assisted recovery of heavy oils and bitumens from sedimentary-rock reservoirs and reveals that geological and geochemical context is an essential consideration. To study mineral effects on gas production, the authors of the complete paper studied a well-characterized oil-containing core and the isolated crude oil from that core. The samples were run at 250 to 300°C in the continued presence of liquid water for 24 hours. The reaction products of all experiments include gases, oil flotate, oil sinkate, water-soluble products, and water-insoluble residues. All reaction products were studied with a variety of analytical techniques, including Fourier-transform infrared spectroscopy, chromatographic fractionation [saturate, resin, and asphaltene (SARA) analysis], gas chromatography mass spectrometry (GCMS), pyrolysis GCMS, and gas chromatography (GC) flame photometric detectors (FPDs)/thermal-conductivity detectors. These techniques were applied to whole oil, maltenes, and asphaltene fractions. Physical properties, including viscosity and density, were also measured.

Laboratory testing was conducted over a 6-year period to aid recovery of oil in the Grosmont formation’s bitumen-bearing carbonate reservoirs, with the intent of providing billions of barrels of oil for the Province of Alberta. Through experiments measuring oil recovery from varying water and steam processes, it was found that wet steam provides the most efficient displacement medium. The oil recovery shows a significant impact of thermal expansion and gas drive, which can lead to significant oil displacements at early times, specifically where the localized open-porosity network fractures is extensive. Bitumen recovery from carbonate systems is achieved through a combination of thermal expansion, gas drive, gravity drainage of oil out of connected open porosity, and imbibition of water into the rock matrix.

Summary Stinger-completion technology is simple to operate and low cost, which can achieve good results in stable oil production by controlling water cut in a bottomwater reservoir. However, most previous studies of stinger completions took place in homogeneous reservoirs and are not equipped to deal with the multipoint watercresting breakthrough caused by fractures or permeability contrast in a heterogeneous bottomwater reservoir. A new improvedstinger- completion (ISC) semianalytical coupled model of reservoir and wellbore flow is established in this article, which considers the impacts of well trajectory, permeability distribution, formation damage caused by drilling and completion, and variable mass flow in a horizontal wellbore. By discrete numerical calculation of the new model, pressure, inflow, and water-cresting profiles can be acquired, and consequently, a design method of ISC is also proposed to be used successfully in a heterogeneous bottomwater reservoir for stable oil production by water-cut control and by optimizing the structure, length, and diameter of the stinger. The successful field application of ISC in the LU-X horizontal well also confirms the feasibility and effectiveness of ISC.

Summary Diagnostic fracture-injection testing (DFIT) has gained widespread usage in the evaluation of unconventional reservoirs. DFIT entails injection of water above the formation-parting pressure, followed by a long-duration pressure-falloff test. This test is a pragmatic method of gaining critical reservoir information (e.g., the formation-parting pressure, fracture-closure pressure, and initial- reservoir pressure), leading to fracture-completion design and reservoir-engineering calculations. In typical field operations, pressure is measured at the wellhead, not at the bottom of the hole, because of cost considerations. The bottomhole pressure (BHP) is obtained by simply adding a constant hydrostatic head of the water column to the wellhead pressure (WHP) at each timestep. Questions arise whether this practice is sound because of significant changes in temperature that occur in the wellbore, leading to changes in density and compressibility throughout the fluid column. This paper explores this question and offers an analytical model for estimating the transient temperature at a given depth and timestep for computing the BHP. Furthermore, on the basis of the premise of a line-source well, we have shown that the early-time data can be represented by the square-root of time formulation, leading to the new modified Hall relation for the injection period.

Summary The study proposes a method for quantitative determination of porosity, permeability, and rock-mechanics properties from drill cuttings of at least 1 mm. The porosity value is used for determining a brittleness index by implementing sonic-derived porosity theory and a dipole sonic log from an offset well. A new parameter is introduced in this work to give a quantitative value to microscopic observations related to natural-fracture features in drill cuttings. It is called “frac value” and in conjunction with the brittleness index and permeability constitutes the main result of the methodology: the cut log. Quantitative data extracted from drill cuttings are important because the amount of information collected in horizontal wells drilled through tight formations, including cores and well logs, is rather limited in most instances. This paper is based on a Canadian case study with implications for selecting optimum intervals for hydraulic fracturing in a tight gas reservoir. However, the method should also be suitable for global applications in all types of reservoirs (unconventional and conventional) where good-quality drill cuttings might be available. Data extracted from the previous steps are useful for multistage hydraulic-fracturing 3D simulation of horizontal wells. This provides additional information to stimulation designers for deciding where to initiate hydraulic fractures and how to optimize fracture spacing and fracture size per stage instead of considering a homogeneous reservoir volume throughout the whole lateral section. It is concluded that the proposed method provides a useful tool for evaluation of direct sources of information that are available in many cases (drill cuttings) but are rarely evaluated quantitatively. The proposed method allows improved design of multistage hydraulic-fracturing jobs in horizontal wells.

Summary A new short-term testing (STT) method is developed and presented in thispaper. The STT method is based on a new semitheoretical analytical solution ofthe diffusivity equation for a cylindrical source and is used to describe thetransient buildup or drawdown pressures for stimulated wells. This solutiongives a good agreement with the results of a numerical ("exact") solution ofthe diffusivity equation. The analytical solution allows us to determine thebottomhole pressure (or pressure derivative) at linear flow andlinear-to-radial flow transition with high accuracy. For small values of time,the STT method gives a half-unit slope straight line (dimensionless pressuredrop is proportional to the square root of time), and for large values of time,the conventional equation for a radial flow can be obtained. The STT method canbe used for any values of flowing or shut-in time. For this reason, theprinciple of superposition can be used without any limitations. In thefollowing, we demonstrate application of the STT method for two acidized oilwells.

Summary Constant-bottomhole-pressure (BHP) solutions to the diffusivity equation areused routinely for the analysis of well-decline performance inboundary-dominated flow (BDF). Gas-well-performance equations for constant-BHPconditions may be written in a number of ways, including rate vs.pseudopressure, rate vs. pseudotime, rate vs. material-balance pseudotimeexpressions, and, more recently, in terms of density-based rescaled exponentialmodels (Ayala and Ye 2013a, b; Ye and Ayala 2013). A significant constraint forsome of these models, especially for the rescaled exponential model, is theassumption that BHP conditions remain constant throughout the declining life ofthe well. However, the most realistic well-specification scenario is that inwhich both BHP and flow rate decline in time (i.e., avariable-pressure-drawdown/-rate condition. In this study, we explore and provethe validity of rescaled exponential and density-based gas decline models forthe analysis of variable-rate/pressure-drop gas systems in BDF. We alsodemonstrate that the constant-rate and constant-BHP solutions given by theproposed density-based decline models for gas wells under BDF areinterchangeable.

Summary Thermodynamic steam-trap control, or subcool control, in a typicalsteam-assisted gravity-drainage (SAGD) production is essential to the stabilityand longevity of the operation. It is achieved commonly through the control offluid production. The goal of such control is to maintain a steady and healthyliquid production without allowing steam from the injector to bypass to theproducer. Therefore, it is effectively a control of the liquid level above theproducer. Unfortunately, it is not practical to monitor this liquid level. Arule-of-thumb subcool-per-metre estimation of 10°C/m of liquid level is popularin the industry; however it does not prove to hold in many situations. Thispaper presents a study of the dynamics of SAGD-production control with aresulting algebraic equation that relates subcool, fluid productivity, andwellbore drawdown to the liquid level above a producer. The main conclusions ofthis study include There is no minimum subcool value for a pure-gravity-drainage scenario;however, as the wellbore drawdown is considered, there is a minimum subcoolvalue in order to maintain the stability of fluid flow. For a given productivity, the liquid level increases as subcool increasesor as wellbore drawdown decreases. For each given set of operating parameters, there exists a criticalproductivity below which SAGD operation would halt. Before the steam chamber reaches the top of the reservoir, the fluidproductivity is limited by the vertical distance between the injector and theproducer; the larger the distance, the higher the fluid production rate canbe. A verification of this analysis was conducted by a series of numericalreservoir simulations. Although limited to two dimensions, we expect that thisanalysis captures the main physics amid the dynamic complexity ofSAGD-production control. The resulting algebraic equation can be used forbetter understanding of the dynamics of subcool control and for determiningoperation strategies.

Summary This work establishes an effective approach to predict pore pressure in theoverpressured Montney shale and overburden from sonic logs by implementingnormal-trend and explicit methods. The cause of the overpressure condition inthe Montney is also addressed. These two methods were selected on the basis ofthe study carried out by Contreras et al. (2012) that worked successfully forpore pressure prediction under subpressured conditions in parts of the westernCanada sedimentary basin (WCSB). As a second objective, the stress-faultingregime was determined in the study area by use of stress polygons and data fromdiagnostic fracture-injection-test analysis as a quantification of the minimumhorizontal stress. This is of paramount importance because there is not ageneric theory explaining the stress-faulting regime for most of the westernregion of the WCSB. The Eaton method from sonic logs (Eaton 1975) and theBowers method (Bowers 1995) were implemented in two vertical wells drilledthrough the Montney shale. The first part of the analysis considered two normalcompaction trends, but unreasonable pressure profiles were obtained andrequired a revision on the depositional environment. It was found that for thestudy area, three normal compaction trends have to be considered. The Bowersmethod was initially implemented using both loading and unloading conditions inorder to establish a safe range of pore pressure to allow successful wellplans. It is concluded that undercompaction could be masked as the onlyoverpressure mechanism in the Montney shale in the study area. The formationexperiences an inverse faulting regime that will lead to the creation ofhorizontal hydraulic fractures. The Eaton method using three normal compactiontrends and an exponent equal to 0.9 works successfully in the study area. TheBowers method uses the loading and the unloading conditions, and the specificcorrelation parameters were found to be suitable for the study area and can beextrapolated to adjacent future production and exploratory wells.

Summary Production forecasting and prediction of original fluids in place are important gas-well-performance evaluations which are routinely conducted using rate/time decline-curve analysis. Currently, rate/time decline-curve analysis of natural-gas reservoirs relies heavily on the use of empirical curve fitting of boundary-dominated rate/time production data using type curves or the Arps hyperbolic decline model. In this study, we show that original fluids-in-place prediction and gas-well-performance evaluations can be conducted simply by straightline analysis of boundary-dominated data in flow-rate vs. cumulative-production plots. We first analytically demonstrate that the hyperbolic decline exponent describing the depletion of single-phase volumetric gas reservoirs is not subject to empirical determination from rate/time data. Decline behaviour of gas wells producing at less than full potential is also shown to exhibit a hybrid decline character: hyperbolic during early boundary-dominated flow and exponential at later times. In both cases, explicit calculations of hyperbolic decline coefficients are possible, thus enabling the explicit calculation of gas reserves using flow-rate vs. cumulative-production straightline plots. Numerical and field case studies are presented to demonstrate the applicability and generality of the proposed reserves determination methodology.

Summary The crossplot of porosity vs. Klinkenberg permeability (PERM) for 378 core samples, drilled from tight gas sands in the Xujiahe formation of the Anlu region-central Sichuan basin, southwest China, showed that tight-gas-sand permeability cannot be estimated effectively from porosity directly because only a poor relationship can be found between core-derived porosity and permeability because of the strong heterogeneity, especially for reservoirs with dominant microfractures (with porosities lower than 6.5%). However, the problem can be solved by introducing the HFU approach. In this paper, the 378 core samples were divided into five types on the basis of the difference of the flow-zone indicator (FZI), and then relationships of rock porosity and permeability were established for every type of core sample. By virtue of the analysis of the expression of FZI and the classical Schlumberger Doll Research (SDR) Center model, a novel technique used to obtain FZI from NMR logs was proposed and a corresponding model was established. The model parameters were calibrated by use of the laboratory NMR measurements of 54 plug samples taken from the Xujiahe formation. Carried out on the experimental data sets, this procedure can be extended to reservoir conditions to estimate consecutive formation permeability along the intervals through which NMR logs were acquired. The processing results of field examples illustrate that the calculated FZI values from field NMR logs match very well with the core analyzed results; the absolute errors among them are within the scope of 60.15. Moreover, permeability, estimated by use of the proposed technique and the core analyzed results are consistent. However, the calibrated SDR model is exclusive to the cases where formation permeability ranges from 0.2 to 0.4 md. To improve permeability prediction with the SDR model, many more core samples drilled from formations with dominant microfractures needed to be tested for laboratory NMR experiments to calibrate the SDR model for each HFU.

Summary Placement of steam-assisted-gravity-drainage (SAGD) surface production pads and subsurface drainage areas in the McMurray formation to maximize the economic potential of an area is a challenging problem. The location of surface pads (SPs) and drainage areas has a large impact on their production performance because of several factors, including variation of bitumen in place, variation of the reservoir base surface, vertical conformance, areal conformance, interaction between different drainage areas and pads, and surface hazards. An optimization algorithm is presented to determine the positions and orientations of SPs and drainage areas over a reservoir area; therefore, the potential for economically recoverable bitumen is maximized. The optimization considers either a deterministic model of the relevant properties or multiple realizations to account for uncertainty. Optimization considers all drainage areas simultaneously to ensure joint optimality of an entire set. The algorithm is demonstrated using two realistic examples that show a significant improvement in potential recovery. The algorithm executes in a reasonable amount of computation time, considering the complexity of the problem.

Summary In a previous study (Clarkson 2009), advanced production-analysis techniques, including production type curves and flowing material balance (FMB), were applied to Horseshoe Canyon (HSC) coal wells to establish the applicability of these techniques and to resolve the importance of multilayer behaviour for production analysis. The field examples chosen for analysis included single wells that exhibited production declines analogous to shallow gas wells, with decline in production occurring from day 1, and in one case exhibiting transient-flow characteristics. There are many more HSC wells that exhibit less-straightforward production characteristics, including flat or even inclining production. These wells have production profiles qualitatively similar to two-phase coalbed-methane (CBM) wells, yet lack water production. There are several possible explanations for the flat or inclining production behaviour, including changing skin associated with near-wellbore cleanup of drilling fluids over time, and increase in absolute permeability associated with matrix shrinkage. Regardless of the cause, these effects need to be accounted for in quantitative production analysis. In this follow-up paper, we continue to perform comparisons between multilayer and single-layer-equivalent production analysis of HSC wells, but focus on wells that exhibit inclining gas production. We develop a methodology to correct for changing skin in both type-curve and FMB analyses that allows this more-complex well behaviour to be analyzed. We validate the new methodology using a simulated example, and then apply it to actual field cases. Changing skin and absolute permeability by layer/coal zone was quantified through periodic shut-in/buildup testing of isolated coals throughout the life of the wells, and these dynamic properties were used in production-data analysis and analytical simulation. Comparing single-layer-equivalent and multilayer analysis, we have found differences in estimated-ultimate-recovery (EUR) values of less than 15% because the existence of one or two dominant (high- kh ) coal zones. Additionally, we investigated the impact of free-gas storage on the results of productiondata analysis of HSC wells. The production-analysis methodology introduced in this work, while useful for analyzing HSC coal wells with dynamic skin/permeability, is expected to be applicable to a broader range of reservoir types that exhibit this complex behaviour.

Summary Our studies of the underlying fundamental gas-recovery mechanisms from shale gas are motivated by expectations of the increasing role of shale gas in national energy portfolios worldwide. We use pore-scale analysis of reservoir shale samples to identify critical parameters to be employed in a gas-flow model used to evaluate well-production data. We exploit a number of 3D-imaging technologies to study the complexity of shale pore structure: from low-resolution X-ray computed tomography (CT) to focused ion beam and scanning electron microscopy (FIB/SEM). We observe that heterogeneity is present at all scales. The CT data show fractures, thin layers, and density heterogeneity. The nanometer-scale-resolution FIB/SEM images show that various mineral inclusions, clays, and organic matter are dispersed within a volume of few-hundred µm 3 . Samples from different regions differ sharply in the shape, size, and distribution of pores, solid grains, and the presence of organic matter. Although the samples have clearly distinguishable signatures related to the regions of origin, extremely low permeability is a common feature. This and other pore-scale observations suggest a bounded-stimulated-domain model of a horizontal well within fractured shale that accounts for both compression and adsorption gas storage. Using the method of integral relations, we obtain an analytical formula approximating the solution to the pseudopressure diffusion equation. This formula makes fast and simple evaluation of well production possible without resorting to complex computations. It ss a decline curve, which predicts two stages of production. During the early stage, the production rate declines with the reciprocal of the square root of time, whereas later, the rate declines exponentially. The model has been verified by successfully matching monthly production data from a number of shale-gas wells collected over several years of operation. With appropriate scaling, the data from multiple wells collapse on a single type curve. Pore-scale image analysis and the mesoscale model suggest a dimensionless adsorption-storage factor (ASF) to characterize the relative contributions of compression and adsorption gas storage.

Summary Previously, nuclear-magnetic-resonance (NMR) carbon-type-analysis data were used to develop a mathematical model of mild thermal conversion (visbreaking) of Athabasca bitumen (Chan et al. 2006). In that work, the major reaction pathways followed during visbreaking were identified. This approach is being extended in the current work to model the visbreaking behaviour of five different oils from different geographical locations around the world. This paper shows the correlation of residue conversion with the contents of different carbon types for five heavy oils from four continents. During visbreaking runs, operators intend to maximize process yields. This is achieved through increasing process severity by raising temperature. However, if the temperature is too high, coke forms. This maximum temperature varies with different crude oils; therefore, as refinery feedstock composition changes, so does the onset of coking temperature. Coke is a hydrocarbon material that has low hydrogen content and is insoluble in the oil. Consequently, this precipitates in the reactor, eventually causing an unscheduled unit shutdown. We have found that contents of specific carbon types in the feed oils correlate with coke formation. This correlation allows prediction of the quantities of coke that will form under the chosen visbreaking (mild thermal) conditions and the "maximum" quantities of coke that would form under coking (severe thermal) conditions.