Tight Oil Wells Research Articles

Understanding the performance of hydraulically fractured wells in the laumontite-rich tight glutenite formation

Massive hydraulic fracturing treatments have been used to produce hydrocarbons from tight glutenite oil reservoirs through both vertical and horizontal wells. Some tight glutenite reservoirs are rich in laumontite. Field experiences indicate that the performance of hydraulically fractured wells on this type of laumontite-rich tight glutenite reservoir typically resulted in low oil productivity and quickly declining oil rates. To understand the poor well performance of these laumontite-rich tight oil wells, extensive laboratory and numerical simulation studies have been conducted to explore the major controlling factors. Laboratory results indicate that the laumontite-rich glutenite reservoir rock has the following characteristics: 1) reservoir permeability is sensitive to stress conditions; 2) reservoir rock has low mechanical strength; and 3) reservoir rock has a low elastic modulus. These geomechanical deformation characteristics strongly affect the well productivity on the laumontite-rich formations. During the hydraulic fracturing and well production phases, the reservoir rock near the main hydraulic fracture can be compacted significantly to reduce rock porosity and permeability. As a result, the fluid flow capacity from the reservoir rock into the hydraulic fracture is reduced. By using laboratory testing data, fully coupled flow-deformation finite element simulations were conducted to study the impact of rock compaction/dilation on well productivity. Based on the numerical simulations, a new hydraulic fracturing scheme was proposed, and a field pilot test was conducted on one vertical well in the study area. Promising field oil production rates were achieved. This paper presents our understanding of the laboratory data, numerical simulation, and field pilot tests results. The new hydraulic fracturing scheme was based on the rock dilation near the main hydraulic fracture. The result indicates that rock dilation, if proactively utilized, can enhance the fluid deliverability from the reservoir into the main hydraulic fracture and boost well productivity.

A workflow based on a semianalytical model to estimate the properties of stimulated reservoir volume of tight-oil wells

Unlike conventional reservoirs, the work in unconventional plays needs to focus on the stimulated reservoir volume (SRV) scale rather than field scale, which requires an integration of many techniques to properly evaluate the SRV properties. There still lacks of a comprehensive integration of micro-seismic, models, and data for SRV, although much work has been done for fracturing estimations of wells with SRV. To narrow the gap, this paper first presents a new semianalytical model to simulate SRV with considering crushed region, effected region, and unstimulated region. The model is based on a boundary element model posed in Laplace domain, and fluid flow in the model is assumed to be two-dimensional, slightly compressible, and single-phase. Following that, a comprehensive fracturing-evaluation workflow is presented for tight-oil reservoir development.The proposed semianalytical model has been verified by numerical solutions. The cost of computation time for the optimized numerical model is about 700 s, while with the proposed model it only cost 100.7-s computation time. The proposed model is efficient and accurate, which provides good support for the fracturing-evaluation workflow. The workflow is an integration of microseismic data, well testing interpretation, rate normalized pressure (RNP) interpretation, and numerical production history match. Its practicability has been demonstrated by a field case from the Junggar Basin. Results show that the most-likely sizes of crushed region and affected region are respectively about 1.8 × 105 and 4.0 × 105 m2, and the permeability values of two regions are about 25 mD and 2 mD. This paper paves a good way to evaluate fracturing and improve future completions in tight-oil reservoirs.

Dynamic coupling of analytical linear flow solution and numerical fracture model for simulating early-time flowback of fractured tight oil wells (planar fracture and complex fracture network)

Abstract Quantitative analysis of flowback data provides an early opportunity to interpret hydraulic fracture properties of fractured wells in unconventional reservoirs. In recent years, a number of studies have been dedicated to the analysis of single-phase flow data prior to hydrocarbon breakthrough and multi-phase flow data after hydrocarbon breakthrough during flowback. This study provides a new model to simulate flowback of fractured tight oil wells with planar fractures or a complex fracture network. In the model, fractures are discretized into a number of segments and the fully numerical method is used to model fracture flow. It is assumed that the pressure interference in the matrix caused by these fracture segments can be accounted using a no-flow boundary condition and that the drainage volumes of fracture segments form isolated regions to allow for linear flow from the matrix to each segment. To model this behavior, matrix flow is simulated using the analytical transient linear flow solution which is dynamically coupled with the fracture flow model by imposing continuity of pressure and flux on the fracture surfaces. The model is simple, but rigorous enough to take into account the important physics of the fracture system, including arbitrary fracture geometries and fracture conductivity distributions. The pressure and saturation gradients of each phase in fractures are accounted for. The ease of model setup and improved computational performance makes it convenient for practical application. The new model is verified with a commercial reservoir simulator. Investigation of the assumption of no-flow boundary condition for the pressure interference in the matrix caused by the fracture segments reveals that the assumption becomes poorer with increasing matrix permeability and decreasing fracture permeability. Flow regime analysis demonstrates that, for planar fractures, water exhibits an early transient linear flow period (first linear flow in the fracture) followed by boundary-dominated flow (first boundary-dominated flow in the fracture) prior to hydrocarbon breakthrough, after which a second transient linear flow in the fracture develops. The final flow period is boundary-dominated flow (second boundary-dominated flow in the fracture), indicating the end time of the flowback period. At this stage, oil will be the dominant phase in the fracture, and will exhibit transient linear flow in the matrix, which is the first flow-regime typically observed during the long-term production period. The case of a complex fracture network exhibits a similar sequence of flow regimes. The second transient linear flow for this case has not been discussed in the literature. The development of this flow period may be caused by the maintenance of fracture pressure, and decrease of water relative permeability due to hydrocarbon contribution from the matrix. A field example from western Canada exhibits the flow regimes noted above and is history-matched successfully using the new model. The results demonstrate the practical application of the new model for deriving reservoir/fracture properties from flowback data and for forecasting.

Mechanism of casing failure during hydraulic fracturing: Lessons learned from a tight-oil reservoir in China

Abstract Casing failures have been systematically encountered during multi-stage hydraulic fracturing of horizontal wells in some unconventional reservoirs of China. Such failures usually manifest themselves as excessive localized radial deformation of the casing after some fracturing stages, which prevent the bridge plugs of subsequent stages from being installed to the design depths, or even result in abandonment of all remaining fracturing stages. In this paper, aiming at clarifying the casing failure mechanism during hydraulic fracturing, we performed an integrated investigation of tight-oil wells in northwest China, by analyzing the field-gained data and modeling possible mechanisms responsible for the casing failure. The investigation results show that, radial deformation of the casing due to alteration of in-situ stresses, even jointly with poor cement sheath, is far smaller than that observed in the field which could reach the order of magnitude of 1–3 cm. In contrast, we find that shear slips of pre-existing fractures/faults crossing the casing can deform the casing to the observed magnitude, justifying a conclusion that casing failure is due to the shear of pre-existing fractures/faults. This modeling-derived conclusion is supported by the records of micro-seismic events. In addition, lead impression blocks have also run for determining the deformed shape of the casing, and the results match the modeling results for the casing sheared by activated fractures/faults. Effect of fracturing pressure, in-situ stresses, length and orientation of pre-existing fractures/faults on the slippage of the fractures/faults and thus the deformation of the casing are demonstrated by a series of sensitivity studies. Additionally, some insights are derived for mitigating the casing failure in future fracturing jobs in similar unconventional reservoirs.

Study on the productivity of the multi-stage fractured horizontal wells in tight oil reservoirs

In this paper, a comprehensive dual-porosity and dual-permeability oil/water flow model that uses experimentally determined reservoir properties to simulate well performance of a multi-stage fractured horizontal well in tight oil reservoirs was established. The numerical simulation results was validated by the commercial simulator Eclipse and field production data. Besides, the effect of threshold pressure gradient, stress-sensitive matrix permeability, stress-sensitive fracture conductivity, and capillary pressure was conducted, revealing that those factors affect the well productivity in different degrees. The results indicate that the threshold pressure gradient can significantly reduce the well productivity. The impact of stress-sensitive coefficient should be significant to oil production in high stress-sensitive tight oil reservoirs. Also, the effects of fracture conductivity and capillary pressure on oil production was studied. This study provides a basis for long-term tight oil production analysis of hydraulically fractured tight oil wells. [Received: October 8, 2016; Accepted: January 28, 2017]

Stochastic Modeling and Assisted History-Matching Using Multiple Techniques of Multi-Phase Flowback from Multi-Fractured Horizontal Tight Oil Wells

In this paper, the methods developed by [1] are used to analyze flowback data, which involves modeling flow both before and after the breakthrough of formation fluids. Despite the versatility of these techniques, achieving an optimal combination of parameters is often difficult with a single deterministic analysis. Because of the uncertainty in key model parameters, this problem is an ideal candidate for uncertainty quantification and advanced assisted history-matching techniques, including Monte Carlo (MC) simulation and genetic algorithms (GAs) amongst others. MC simulation, for example, can be used for both the purpose of assisted history-matching and uncertainty quantification of key fracture parameters. In this work, several techniques are tested including both single-objective (SO) and multi-objective (MO) algorithms for history-matching and uncertainty quantification, using a light tight oil (LTO) field case. The results of this analysis suggest that many different algorithms can be used to achieve similar optimization results, making these viable methods for developing an optimal set of key uncertain fracture parameters. An indication of uncertainty can also be achieved, which assists in understanding the range of parameters which can be used to successfully match the flowback data.

Analytical modeling of linear flow in single-phase tight oil and tight gas reservoirs

Unconventional reservoirs, including tight oil, tight gas and shale gas are economically attractive, but operationally challenging, particularly for cases when complex flow behavior occurs within the reservoir. Accounting for the physics of flow in such formations is central to providing improved short- and long-term oil and gas production forecasts. At the early phase of development of these reservoirs, and in the presence of limited data, analytical models are more suited for mechanistic studies leading to improved understanding of the reservoir. Analytical models often utilize solutions to flow equations for liquids with constant viscosity, and small and constant compressibility. In tight formations, however, these assumptions simply do not apply as fluid and rock properties change with pressure drawdown. Historically, efforts have concentrated on linearizing the governing partial-differential equations to account for these effects by employing appropriately defined pseudopressure and pseudotime functions. A rigorous approach for determination of pseudotime includes the use of average pressure in the distance of investigation during transient flow.In this work, an analytical expression for average reservoir pressure in the (dynamic) drainage area is derived for constant pressure and constant rate production scenarios. By deriving an explicit relation for average pressure in the drainage area as a function of the initial reservoir pressure and the wellbore pressure, the iterative procedure for calculation of pseudotime is relaxed. Using the developed expression for average pressure in the distance of investigation, the pseudo steady-state deliverability equation is extended to model the transient period by incorporating the dynamic drainage area concept in the productivity index equation. We first verify the applicability of the developed approach for oil reservoirs and later demonstrate that the approach is considered to be useful for analysis of production data from tight gas reservoirs.The established methodology in this work provides a useful tool for rapid forecasting of tight oil and tight gas wells, allowing for the examination of the effects of different parameters on the forecast.

Is the US the New Swing Producer? The Price Responsiveness of Tight Oil

We analyze the price responsiveness of onshore oil supply from conventional versus new unconventional “tight” formations in the United States. We separately analyze three key stages of oil production: drilling wells, completing wells, and production from completed wells. We find that the important margin is drilling investment. We estimate drilling responses of approximately 1.3 percent for tight oil and 1.1 percent for conventional oil per 1 percent change in oil prices. In addition, tight oil wells produce about 4.6 times more oil compared to conventional ones. Together, the long-run price responsiveness of supply is about 5 times larger for tight oil on a per well basis, and about 9 times larger when accounting for the rise in the number of unconventional wells drilled. Based on these estimates, simulations of the time-profile of oil production response to price changes show that the US supply response is much larger now due to the shale revolution. Nonetheless, it takes many months before a substantial portion of the full supply response is online, longer than the 30 to 90 days typically associated with the role of “swing producer” such as Saudi Arabia.

E&P Notes (September 2017)

E&P Notes Researchers: Models Overstate Technology Impact, Understate Location Impact for Unconventional Wells Joel Parshall, JPT Features Editor The role of new technological improvements in the increasing productivity of tight oil and shale gas wells is likely being overestimated because of models that inadequately consider the influence of drilling in reservoir core areas, a pair of researchers at the Massachusetts Institute of Technology Energy Initiative (MITEI) have said in a new paper. With the steep fall in oil prices since late 2014, field operators are drilling fewer wells and have shifted their targets to only the most prospective acreage. The oil industry’s often well-publicized gains in well productivity significantly reflect the impact of drilling and hydraulic fracturing operations focused on reservoir “sweet spots,” MITEI’s Justin Montgomery and Francis O’Sullivan write in a paper in Applied Energy. Drilling Boom Goes Flat Stephen Rassenfoss, JPT Emerging Technology Senior Editor Growth in the US rig count stalled in mid-July, in what could be a sign of things to come. After doubling over the previous 12 months, the rig count remained flat, slipping to 949 as of 11 August, according to the Baker Hughes Rig Count. But surveys of industry insiders by the Federal Reserve banks of Dallas and Kansas City see that rally running out, with shrinking spending on capital expenditures (Capex) and drilling. “We see the expected Capex and expected drilling number are still positive. It is a lot less positive than in the first quarter and certainly in the fourth quarter of last year,” said Chad Wilkerson, the branch executive and economist at the Kansas City Fed’s Oklahoma City branch, adding, “Leveling seems to be the story.” US Daily Oil Production To Break Record in 2018 Joel Parshall, JPT Features Editor Average total crude oil production in the United States is expected to reach a record level of 9.9 million B/D in 2018, the US Energy Information Administration (EIA) said in its latest forecast. The projected output would surpass the 9.6 million B/D that the US produced in 1970. The forecast said that total US crude oil production will average 9.3 million B/D this year, an increase of 500,000 B/D from 2016. Most of the production growth from June through the end of next year is expected to come from tight rock formations in the Permian region of Texas and from the Federal Offshore Gulf of Mexico (GOM). IEA: US May Be Top LNG Exporter by 2022 Trent Jacobs, JPT Digital Editor The US may become the global leader in liquefied natural gas (LNG) exports, according to a new report by the International Energy Agency (IEA). To ascend to the top spot, US LNG shipments must surpass today’s leading exporters, Australia and Qatar. The IEA called US LNG a “catalyst for change” and highlighted how production from tight shale gas fields is transforming the world’s natural gas marketplace. The Paris-based organization also said the country’s exports will help fuel economic growth in developing countries.

Production Decline Curves of Tight Oil Wells in Eagle Ford Shale

This study derives typical production curves of tight oil wells based on monthly production data from multiple horizontal Eagle Ford shale oil wells. Well properties initial production (IP) rate and production decline rate were documented, and estimated ultimate recovery (EUR) was calculated using two empirical production decline curve models, the hyperbolic and the stretched exponential function. Individual well productivity, which can be described by IP level, production decline curvature and well lifetime, varies significantly. The average monthly IP was found to be around 500 bbl/day, which yields an EUR in the range of 150–290 kbbl depending on used curve, assumed well lifetime or production cutoff level. More detailed analyses on EUR can be made once longer time series are available. For more realistic modeling of multiple wells a probabilistic approach might be favorable to account for variety in well productivity. For less detailed modeling, for example conceptual regional bottom-up production modeling, the hyperbolic function with deterministic parameters might be preferred because of ease of use, for example with the average parameter values IP = 500 bbl/day, D = 0.3 and b = 1 resulting in an EUR of 250 kbbl with a 30-year well lifetime, however, with the recognition that this extrapolation is uncertain.

Drill-Bit Parity: The Increasing Importance of Supply-Side Links in Oil and Gas Markets

Previous economic analyses focused on relationships between crude oil and natural gas markets centered primarily on demand-side considerations. We provide evidence that two important supply-side connections play important roles in understanding crude oil and natural gas market integration. First, crude oil production and natural gas production require a common capital input: rotary drilling rigs. Competition for this capital input should be expected to keep the difference between crude oil and natural gas prices in check. Second, crude oil wells produce associated gas, while natural gas wells often produce associated oil or oil substitutes. This latter supply-side connection could cause divergence in crude oil prices and natural gas prices, because a price shock for one commodity will increase associated production of the other commodity. Understanding which effect dominates at a particular time is essential to understanding oil and gas market integration. We construct a theoretical model based on the profit-maximizing decisions of a drilling-rig allocating firm to delineate the role played by these supply-side factors in oil and gas market integration. If rig competition is the more important supply-side factor then gas-rig allocations and oil prices will be negatively related, and vice versa, while if associated commodity flows are more important then gas-rig allocations and oil prices will be positively related, and vice versa. We then test the predictions of the theoretical model using three econometric methods, and find ample evidence of long-run relationships driven by these supply-side factors. However, we provide evidence indicating that drilling responses to price changes are unstable across time, and drilling rig competition has come to play a more important role since the onset of increasing production from shale gas and tight oil wells, which began in the mid-2000’s.

Semi-analytical model for matching flowback and early-time production of multi-fractured horizontal tight oil wells

Analysis of multi-fractured horizontal well (MFHW) production data completed in low-permeability (tight) oil reservoirs has traditionally focused on long-term (online) production after the initial flowback period. Recent studies, however, have demonstrated that important information about hydraulic fractures can be ascertained from flowback data and simulation studies are now being designed to model flowback along with the online production.In this work, a new semi-analytical model is developed specifically for modeling water and hydrocarbon production during flowback and early-time production for tight oil wells. Two flow regions are assumed: a primary hydraulic fracture (PHF) and an enhanced fracture region (EFR) adjacent to the hydraulic fracture, where reservoir permeability has been enhanced due to stimulation. Alternatively, a non-stimulated matrix region (NSR), where reservoir permeability is not enhanced due to stimulation, may be placed adjacent to the PHF. A coupled PHF-EFR model is created by assigning the average pressure in the PHF as the inner boundary condition of the EFR, and wellbore flowing pressure as the inner boundary-condition for PHF. If the initial fracture pressure is greater than reservoir pressure, the coupled model forecasts initial production to be single-phase flow of fracturing fluid, followed by two-phase flow of fracturing fluid and formation oil from the EFR to the PHF after breakthrough to the fracture. Transient flow of fluids through the PHF and EFR is modeled with the dynamic drainage area approach. Equations of coupled flow/material balance are solved iteratively at each timestep. Stress-dependent properties of fractures and matrix are handled in the solution.The robustness of this innovative approach is tested through comparison with more rigorous numerical simulation, and its practicality demonstrated with a field example. The new technique should serve as a useful tool for petroleum engineers responsible for forecasting tight oil wells exhibiting these complexities.

Flowback Fracture Closure: A Key Factor for Estimating Effective Pore Volume

Summary The importance of evaluating well productivity after hydraulic fracturing cannot be overemphasized. This has necessitated the improvement in the quality of rate and pressure measurements during flowback of multistage-fractured wells. Similarly, there have been corresponding improvements in the ability of existing transient models to interpret multiphase flowback data. However, the complexity of these models introduces high uncertainty in the estimates of resulting parameters, such as fracture pore volume (PV), half-length, and permeability. This paper proposes a two-phase tank model for reducing parameter uncertainty and estimating fracture PV independent of fracture geometry. This study starts by use of rate-normalized-pressure (RNP) plots to observe changes in fluid-flow mechanisms from multistage-fractured wells. The fracture “pressure-supercharge” observations form the basis for developing the proposed two-phase tank model. This model is a linear relationship between RNP and time, useful for interpreting flowback data in wells that show pseudosteady-state behavior (unit slope on log-log RNP plots). The linear relationship is implemented on a simple Monte Carlo spreadsheet. This is then used to estimate and conduct uncertainty analysis on effective fracture PV by use of probabilistic distributions of average fracture compressibility and gas/water saturations. Also, the proposed model investigates the contributions of various drive mechanisms during flowback (fracture closure, gas expansion, and water depletion) by use of quantitative drive indices similar to those used in conventional reservoir engineering. Application of the proposed tank model to flowback data from 15 shale-gas and tight-oil wells estimates the effective fracture PV and initial average gas saturation in the active fracture network. The results show that fracture-PV estimation is most sensitive to fracture closure compared with gas expansion and water depletion, making fracture closure the primary drive mechanism during early-flowback periods. Also, the initial average gas saturation for all wells is less than 20%. The parameters estimated from the proposed model could be used as input guides for more-complex studies (such as discrete-fracture-network modeling and transient-flowback simulation). This reduces the number of unknown parameters and uncertainty in output results from complex models.

History Matching and Forecasting Tight Gas Condensate and Oil Wells by Use of an Approximate Semianalytical Model Derived From the Dynamic-Drainage-Area Concept

SummaryRecently, low-permeability (tight) gas condensate and oil reservoirs have been the focus of exploitation by operators in North America. Multifractured horizontal wells (MFHWs) producing from these reservoirs commonly exhibit long periods of transient flow, during which two-phase flow of oil and gas begins because of well flowing pressures dropping to less than saturation pressure. History matching and forecasting of such wells can be rigorously performed by use of numerical simulation, but this approach requires significant data and time to set up. Analytical methods, although requiring fewer data and less time to apply, have historically been developed only for single-phase-flow scenarios. In this work, a novel and rigorous analytical method is developed for history matching and forecasting MFHWs experiencing multiphase flow during the transient and boundary-dominated flow periods.The distance-of-investigation (DOI) concept has been used for many years in pressure-transient analysis to estimate distances of reservoir boundaries to wells, among other applications. In the current work, the DOI concept is used to estimate dynamic drainage area (DDA) to forecast tight gas condensate and oil wells; a linear flow geometry is assumed. During transient flow, the DDA is calculated at each timestep by use of the linear-flow DOI formulation; a multiphase version of the linear-flow productivity-index (PI) equation and material-balance equations for gas, condensate, and oil are solved iteratively for pressure, saturation, and fluid-production rate. The PI equations for gas and oil use pseudopressure, which is evaluated with saturation/pressure relationships derived from pressure/volume/temperature data. For boundary-dominated flow, when the drainage area is static, the inflow equations are again coupled with material balance for both phases.The new method is validated against numerical simulation, covering a wide range of fluid properties and operating conditions. The new method matches the simulation acceptably for all cases studied. Field examples of MFHWs are also analyzed to demonstrate the practical applicability of the approach. The three liquid-rich shale examples analyzed were also chosen to represent a wide range of fluid properties. In all cases, acceptable history matches are achieved.The new analytical forecasting/history-matching procedure developed in this work provides a practical alternative to numerical simulation for tight gas condensate and oil experiencing two-phase flow during the transient-flow period. The method, which does not rely on Laplace-space solutions, is conceptually simple to understand, easy to implement, and avoids the inconvenience of Laplace-space inversion.

Numerical investigation of limitations and assumptions of analytical transient flow models in tight oil reservoirs

The complex fracture network created by multistage hydraulic fracturing has been recently described by triple porosity models. Existing triple porosity models typically assume sequential flow from matrix to micro fractures and from micro fractures to hydraulic fracture. Modeling simultaneous depletion of a matrix block into both micro and hydraulic fractures entails solution of a two dimensional continuity equation that is challenging by analytical or even semi-analytical methods. In addition, analysis with analytical models and type-curves provides deterministic and homogeneous estimates, rendering uncertainty analysis of fracture properties difficult.In this paper, we use a commercial reservoir simulator to compute the transient response in a segment of a hydraulically fractured horizontal well with a triple-porosity model, where matrix and fracture elements are explicitly discretized. Some limitations in analytical models such as sequential flow, single-phase flow and fully-connected symmetric fractures are investigated using the actual rate data from two tight oil wells completed in the Cardium and Bakken formations. An early drop in production, as commonly observed in many tight oil wells, could be attributed to gas dissolution with pressure decline and multiphase flow effects. Impacts of pressure interference between natural fractures and inter-well fracture communication are also investigated. Uncertainty in model parameter estimation is studied by assuming that results obtained from analytical solutions would characterize the mean estimate of the corresponding fracture parameters, additional heterogeneous models of natural/induced micro-fracture properties including its total number and intensity (spacing) are assigned stochastically. These models are subsequently subjected to flow simulations, and the variability in production performance captures the sensitivity due to model parameter uncertainties. Our results highlight the non-uniqueness of fracture characterization in production data analysis. It is demonstrated that ignoring the uncertainty in history-matched parameters and assumptions associated with analytical models could potentially over- or under-estimate production by up to 30%. The analysis workflow adopted in this study presents a practical framework for integrating numerical simulations with analytical solutions to study the limitations of analytical transient flow models and to quantify the uncertainty in production performance predictions.

A semi-analytical method for forecasting wells completed in low permeability, undersaturated CBM reservoirs

Exploration and development of coalbed methane (CBM) reservoirs is ongoing in the Asia Pacific region, with low permeability, undersaturated coals being the target in some areas. Horizontal wells are typically required to produce low permeability CBM reservoirs at commercial rates, and may experience a period of single-phase (water) transient flow, followed by a transition to two-phase (water + gas) transient flow. Wells exhibiting this behavior are particularly difficult to model analytically, yet simple analytical and semi-analytical tools are desirable for making quick, but reasonably accurate forecasts. The purpose of this work is to therefore provide a new forecasting methodology for low permeability, undersaturated CBM wells.The new method for forecasting CBM wells introduced in this work is based on the concept of a dynamic drainage area (DDA), recently adapted to forecast tight black oil and gas condensate wells exhibiting two-phase flow. A critical advancement provided in the current work is modeling the transition from single-phase flow of water to two-phase flow of gas and water during the transient linear flow period, which was not attempted for the black oil/gas condensate cases. Above desorption pressure, material balance, performed on the dynamic drainage area to determine average pressure in the distance of investigation, is combined with the linear flow productivity index equation to forecast water production at each time step. For two-phase flow below desorption pressure, the two-phase version of the linear productivity equation and material balance equations for water and gas are solved iteratively for pressure, saturation and fluid production rate within the DDA. The gas material balance equation accounts for desorption effects. In order to calculate the DDA at each time step, the linear flow distance of investigation equation is used. Importantly, using the DDA method, variable operating conditions (flowing pressures) may be accounted for, which is critical for CBM wells during early stages of production.The new semi-analytical DDA model is used to history-match production data from an actual horizontal well completed in a low permeability, undersaturated, western Canadian CBM reservoir. Further, the match is compared to that obtained from rigorous numerical simulation. The history-match of the field data is reasonable with the new model and comparable to numerical simulation. The new model is however easier to setup and less data-intensive than numerical simulation, providing a practical alternative to CBM reservoir engineers who are responsible for generating a large number of forecasts.

A new semi-analytical model for simulating the effectively stimulated volume of fractured wells in tight reservoirs

The interaction of hydraulic fractures and natural fractures results in a complex fracture network system around a producing well, which is the primary contributing region for production in unconventional reservoirs. Currently, most models for simulating fluid flow in formations penetrated by fractured wells are based on the assumption of a homogeneous dual–porosity medium.In this paper, a new semi-analytical model is presented for vertically fractured wells with stimulated reservoir volumes (SRV). Specifically, we employ fractal porosity and permeability to describe the heterogeneous distribution of porous media in a SRV. An approach is given for estimating the size and equivalent permeability of the fractal SRV for vertically fractured wells in tight reservoirs. The line source function, Laplace transformation, integral of the modified Bessel function and Stehfest numerical inversion algorithms are used to solve the composite model. Based on the Duhamel principle, the dimensionless pressure responses of tight oil and gas wells in the Laplace domain and time domain are obtained. Flow regime diagnostics of vertically fractured wells in tight reservoirs are characterized. Sensitivity analysis, including the effects of SRV parameters and fractal parameters on pressure responses and linear flow, are performed. The results show that seven primary regimes can be divided into pressure response curves. The size and equivalent permeability of the fractal SRV can be calculated by the dimensionless pressure derivative curves. In a complex fractal reservoir, the larger the connectivity index is and the smaller the fractal dimension is, the more significant the heterogeneity of the fractal SRV is and the larger the slopes of linear flow are, which leads to a smaller equivalent permeability of the fractal SRV radius. The presented model and the results in this paper can enrich the pressure transient analysis models for vertically fractured wells in unconventional reservoirs.

Pseudo-steady state analysis in fractured tight oil reservoirs

The log–log plots of normalized rate versus material balance time of two fractured horizontal wells completed in the Cardium and Bakken formations show three distinct regions of quarter, half and unit slopes. The first two regions can be interpreted by the existing semi-analytical models for bi-linear and linear transient flow. This study develops a pseudo-steady state (PSS) model for linear dual porosity reservoirs that describes the third region (unit slope). The application of this PSS model on field production data from two tight oil wells yields reasonable estimates of hydraulic fracture half-length and average matrix permeability. Also, this paper demonstrates how the proposed PSS analysis complements the transient linear analysis commonly used in industry.