Liquid-rich Gas Research Articles

Numerical investigation and performance enhancement of an ammonia-water radial-outflow turbine through the flow-oriented optimization

The radial-outflow turbine has advantages due to its liquid-rich gas adaptability when applied in a Kalina ammonia-water cycle system for the utilization of geothermal energy and waste heat. However, the existing radial-outflow turbine shows relatively lower efficiency than the conventional radial-inflow turbines due to its distinct stage configuration and the lack of efficient design method. In the present study, numerical investigation has been conducted on a radial-outflow turbine adopted in Kalina cycle system, by which the turbine flow losses are analyzed. To enhance the turbine performance, a design optimization method has been developed, which includes the following features: the flexible geometry variations are realized to explore the optimization potentials, where the stator and rotor blades are optimized simultaneously; the flow-oriented objective function is established to drive the optimizer to suppress the flow losses in blade passages while adjust the flow matching. To solve the complex geometry optimization problem, adaptive optimization algorithm is imported to accelerate global searching and reduce the costly Computational Fluid Dynamics evaluations. The developed optimization method has been applied in the geometry optimization of a radial-outflow ammonia-water turbine. Benefitting from the fine-tuned blade geometries, the flow matching between stator and rotor is adjusted and the flow losses are mitigated. Thus, the turbine efficiency and shaft power are improved by 6.46% and 5.85%, respectively.

Multipoint Design Optimization of a Radial-Outflow Turbine for Kalina Cycle System Considering Flexible Operating Conditions and Variable Ammonia-Water Mass Fraction

The radial-outflow turbine has advantages due to its liquid-rich gas adaptability when applied in the Kalina ammonia-water cycle system. However, the operational conditions of the turbine often deviate from its design values due to changes of the heat source or the cooling conditions, and such deviates may deteriorate the flow behavior and degrade the turbine performance. To enhance the turbine efficiency at complex conditions for flexible running of the Kalina cycle system, a multipoint design optimization method is developed: the flexible operating has been defined by three critical, dimensionless parameters, which cover a wide range in a 3D operating space; the representative off-design points are identified to define the objective function; and adaptive optimization methods are integrated to permit optimization searching using limited CFD callings. The developed multipoint design method is adopted to improve the turbine performance under complex operating conditions. The obtained results demonstrate that the application of the developed multipoint optimization method effectively eliminates the flow separation at various operating conditions; thus, the turbine off-design performance has been comprehensively improved.

Reducing uncertainty in unconventional reservoir hydraulic fracture modeling: A case study in Saudi Arabia

Saudi Aramco is exploring and appraising liquid rich and dry gas unconventional reservoirs. Part of this effort has focused on understanding the effective fracture geometry and its role in optimal well spacing and reservoir drainage. A review of collected data and existing hypotheses indicated that there are multiple models for optimal production yet each calls for a dramatically different approach. Long term flow data is recommended in such cases but this is often complicated by the fact that decisions in a fast paced environment might rely on short production history.A field pilot in a carbonate-rich ultra-low permeability source rock in Saudi Arabia incorporated multiple hydraulic fracture monitoring techniques to validate outputs from a classical linear elastic fracture model. All employed monitoring techniques had their results assessed in conjunction with their strengths and weaknesses for more inclusive interpretations. From the reservoir flow regimes and the various hypotheses on effective fracture geometries, the extent to which non-uniqueness impacts determination of the most probable fracture geometry and matrix permeability was investigated. Long and short hydraulic fractures were used to match the short production history with reservoir simulation models under different sets of assumptions. The contradictions in the assumptions and difficulty in transferring fracture geometries, calibrated by the monitoring results, to production data modeling, were used to gauge the validity of associated effective fracture geometry hypotheses.From the pilot, microseismic monitoring indicated that more stimulation volumes yielded longer microseismic geometries. Offset well stimulation induced pressure interference in adjacent wells. Cross-well hydraulic communication illustrated by chemical and oil tracers corroborated the longer fractures mapped by microseismic events and also predicted by linear elastic fracture models. In addition, the sequential opening of the pilot pad wells induced subtle production-induced pressure interference in the early flow period. While the subtle production-induced pressure interference was initially thought to be the ground truth for adequate well spacing, it was shown that it was not unique due to the fact that ultra-low matrix permeability can prolong onset of fracture interference. The hydraulic fracture monitoring methods showed identical results for the estimated hydraulic fracture half-length which allowed the constraining of the parameter. Reservoir simulation was used to match the short production history with both short and long planar fractures even though the former had not been validated by most of the observed data. Consideration of all observed data, dimensionless fracture conductivity for stimulation design criteria and the reservoir simulation assumptions provided validation for long effective fractures.This study shows the contribution of a diverse surveillance data acquisition in reducing uncertainty in unconventional reservoir fracture modeling for realistic reservoir simulation and development solutions. In addition, insights derived from this work provided important clues for testing the validity of hypotheses in unconventional reservoir studies.

Impact of un-propped fracture conductivity on produced gas huff-n-puff performance in Montney liquid rich tight reservoirs

Studies have shown that the gas huff and puff injection potentially perform better than the continuous gas flooding in enhancing the hydrocarbon recovery in the liquid rich tight reservoirs. During the fracturing stimulation, only part of the induced hydraulic fractures is propped because proppants cannot be carried to the fracture tips. Moreover, some secondary and tertiary fractures may be too narrow to accommodate any proppants. The conductivity of the unpropped fractures is highly dependent on the variation of the in-situ pressure and may be open and close periodically during the huff-n-puff cycles. In this study, the stress-dependent fracture conductivity and its impact on the produced gas huff-n-puff performance are investigated in a liquid rich tight reservoir, considering the existence of the large amount of the unpropped fractures. The experimental data of stress-dependent fracture conductivity is employed first to simulate the dynamic conductivity during the depletion and the gas huff and puff cycles. A reservoir model is then constructed and history-matched based on the reservoir fluid samples and the field production data collected from the Montney liquid rich tight reservoir in Western Canada. Performance of the produced gas huff-n-puff is examined in the targeted reservoir and results show that contributions of the unpropped fractures cannot be ignored, which leads to 7.8% more condensate (i.e., oil) production and 2.8% higher in barrel of oil equivalent (BOE), compared to the case with propped fractures only. The effects of complex fracture geometry and the cluster completion are also investigated and results show that the unpropped fracture contributions towards the condensate production and BOE are even more pronounced in the complicated scenarios. The condensate oil and BOE are 42.0% and 22.9% higher in complex fracture geometry case and 12.4% and 5.6% higher in the fractures with multiple clusters than those scenarios with propped fractures only. This paper provides a better understanding on the potential performance of enhanced hydrocarbons recovery in liquid rich tight gas reservoirs via gas huff-n-puff operations.

Resource Growth Through Petroleum Exploration in PNG

Mesozoic and Tertiary clastic and carbonate reservoirs are prolific producers of high quality liquid-rich gas onshore PNG. LNG projects are among the lowest cost and most profitable globally. Accordingly there has been a recent resurgence of petroleum exploration in PNG.In 2015 Oil Search undertook a country-wide petroleum Common Risk Segment analysis that highlighted potential for giant new oil and gas fields of sufficient scale to support future LNG projects. It also concluded that 40 trillion cubic feet of gas plus 550 million barrels of oil resources remain to be found (representing approximately 60% of PNG’s total petroleum resource).In 2016 Oil Search completed an ambitious integrated structural, stratigraphic, burial, maturation, migration, uplift and erosion model of PNG’s total petroleum system to quantify the locations for highly prospective under-explored regions.Tectonic events at plate and basin scales were re-assessed and correlated within a new country-wide PNG Chrono-stratigraphy of regionally mappable sequences and flooding events, some of Global extent.A Base Tertiary Mega-Sequence Boundary is mappable over the entire onshore to deepwater regions. 130 1D burial models combined with restored 2D structural and stratigraphic cross sections, have contributed to a new regional petroleum charge model of the Foldbelts, Foreland and Offshore regions.It is concluded that petroleum was generated pre- foldbelt during Late Cretaceous times in interior PNG while petroleum is currently being generated at the present day mountain front.A holistic 4D charge model explains why very young foldbelt traps are petroleum charged.

Australia's premier shale basin: five plays, 1 000 000 000 years in the making

The successful fracture stimulation and production test of the Amungee NW-1H well placed the Velkerri Shale play and the Beetaloo Sub-basin on Australia’s energy radar. The Velkerri Shale dry gas play is currently Australia’s most promising shale gas prospect; however, it is not the only prospect in the Beetaloo Sub-basin. Four additional potential plays have been identified, each with their own specific risk profile and relative benefits. These are the Velkerri Shale liquids rich gas play, the Kyalla Shale and hybrid liquids rich gas plays, and the Hayfield Sandstone oil/condensate play. Appraising each of these opportunities requires special attention to ensure efficient and appropriate deployment of capital. A framework approach allows for the high-level assessment and comparison of each of the discussed opportunities within the Beetaloo Sub-basin portfolio.

A semi-analytical solution to compositional flow in liquid-rich gas plays

Liquid-rich gas (LRG) reservoirs can exhibit complex phase and flow behavior due to gas condensation and re-vaporization and differences in phase mobilities that results in compositional variations inside the system. To date, the analysis of composition variation in liquid-rich wells has been largely limited to numerical modeling. This work uses a similarity-based analytical approach to study the in situ and flowing fluid composition of gas condensate wells producing under infinite-acting linear and radial flow under constant bottomhole pressure (BHP) condition. We propose a semi-analytical solution to the governing partial differential equations (PDEs) written in terms a compositional fluid formulation for multiphase (gas, oil and water) flow system in liquid rich gas reservoirs. The proposed solution is developed using similarity-theory (i.e. Boltzmann’s transformation) and is validated by both analytical development and numerical simulation data. Using proposed method, pressure and overall composition are solved simultaneously and rigorously without any kind of simplification or approximation, from which producing fluid composition can be fully predicted prior to the availability of field production data. Moreover, results corroborate that when LRG wells are producing under 1D linear regime – a commonly-observed flow condition for hydraulically-fractured horizontal wells completed in unconventional formations – and against a constant BHP constraint, the producing wellbore fluid composition remains constant as long as the system remains infinite acting, leading to a constant producing gas-oil ratio (GOR). For radial flow, however, producing wells team composition and GOR are shown to be time-dependent before stabilization at a nearly-constant value.

Use of rescaled exponential models for boundary-dominated liquid-rich gas flow analysis under variable bottomhole pressure conditions

The analysis of production data from natural gas reservoirs can serve as one of the most powerful tools to estimate remaining reserves and provide a forecast of its future performance. While fundamentals of decline for dry gas reservoirs are well described in literature, those for liquid-rich gas reservoirs are yet to be well-understood. Any predictive model used to analyze these reservoirs must account for the inherent changes in reservoir fluid composition during their producing life due to condensate dropout within the reservoir, once reservoir pressure falls below dew point pressure. This study presents a mathematical model capable of predicting non-linear flow behavior in multiphase gas-condensate reservoirs using rescaled exponential models applicable to boundary-dominated flow regimes under variable bottomhole pressure conditions. We develop a set of analytical solutions for surface oil and total hydrocarbon flowrates, for wells producing under variable bottomhole pressure. We model hydrocarbon production from gas-condensate reservoirs by employing a material balance over produced condensate and total hydrocarbons. In this material balance approach, we use equivalent fluid molar densities in multiphase systems, resulting in analytical equations for the different flowing phases. The developed set of analytical solutions aims at providing an accurate estimate of reservoir behavior and available reserves, which can be used to inform critical economic decisions for further development of the reservoir. The proposed rescaled models minimize assumptions and stay true to the physics of multiphase flow. We demonstrate that the developed analytical model closely predicts the numerical simulation results for the hydrocarbon flowrates as well as the estimated reserves where a wide range of gas-condensate reservoirs, from lean to liquid-rich, is considered.

Similarity-based, semi-analytical assessment of capillary pressure effects in very tight, liquid-rich gas plays during early-transient multiphase analysis

In state-of-the-art production data analysis (PDA) methodologies applied to multiphase flow, capillary pressure is typically neglected in order to enable analytical treatment. However, neglecting the amplified role of capillary pressure in multiphase flow in unconventional formations may generate misleading analysis results during production forecasts and reserve estimations. This work proposes a similarity-based, semi-analytical model eminently applicable to rate transient analysis of unconventional multiphase systems that fully considers the capillary pressure effect. The similarity-based method is developed by solving the governing equations applicable for multiphase flow in early-transient multiphase systems simultaneously, highlighting the effect of capillary pressure not only as an additional pressure gradient for flow but also on fluid PVT properties and hence mobilities and accumulation terms. To arrive at the proposed semi-analytical solution, we apply the similarity method or Boltzmann transformation to the governing system of PDEs, and the resulting system of ODEs is solved simultaneously for pressure and saturation via a shooting method coupled with Runge-Kutta integration. The validity of the series of proposed similarity-based semi-analytical solutions that capture capillary pressure effects is verified by discussing a number of cases studies and comparison against full-scale numerical simulation data.

New forecasting method for liquid rich shale gas condensate reservoirs with data driven approach using principal component analysis

Accurate production performance evaluation and forecasting in shales during the early stages of development can play an important role in minimizing uncertainties associated with unconventional reservoirs. Given the limited reliability in forecasts from traditional decline models when applied to unconventional reservoirs, new tools to supplement the ones in use today are required to improve the accuracy of production forecasts. In this study, we present a method involving principal component analysis (PCA), which is a simple, non-parametric method of extracting relevant information from large data sets to perform production forecasting of liquid rich shale gas condensate reservoirs.We used a comprehensive compositional reservoir model to create several iterations of synthetic production histories from liquid rich shales (LRS) wells based on Monte Carlo simulation with predefined probability distributions. Cumulative gas, gas rate, and condensate-to-gas ratio (CGR) for the simulated cases were decomposed into principal component (PC) scores and coefficients were used to recreate the original data. The dataset was cross-validated to check its ability to predict the missing production data based on PC scores and coefficients of the limited production data. Principal component analysis was further applied to the field data from several wells from Eagle Ford shale. We re-created and cross-validated the field data by using limited PC which led to good matches of the original production data. Two to three PC's were required to recreate the initial data with reasonable accuracy depending on the quality of the input data. During the validation step, we observed that some of the wells exhibited significant error which could be attributed to significantly different production profiles of those wells compared to the other wells. For simulated data, four PC was enough to yield the prediction with average error of 0.16%, 0% and 0.77% respectively for gas rate, cumulative gas and CGR respectively. For field data, three PC yielded the best prediction with average error of 1.63% and 2.98% for gas rate and oil rate respectively.This work shows that multivariate statistics and data driven methods can be used as an important approach to complement existing tools like reservoir simulation and decline curve analysis to perform production data analysis. PCA can also be used and can generate accurate results relatively quickly. We recognize that even more rapid approximate methods will be required for routine analysis. Understanding the limitations of different approximate methods and application of methods to overcome these limitations in given circumstances should lead to optimal use of these methods.

On the pressure-saturation path in infinite-acting unconventional liquid-rich gas reservoirs

Unconventional liquid rich natural gas reservoirs exhibit a number of unique technical challenges, including ultra-low rock permeability, which can lead to prolonged periods of infinite-acting flow. Despite this, traditional production data analysis techniques often assume boundary-dominated conditions, which may not be experienced by unconventional systems for very long stretches in their productive life. Analysis of two-phase flow and well production often relies on the use of two-phase pseudo-variables calculations for which the fluid saturation-pressure relationship must be estimated a priori. The de-facto assumption is that such a priori reservoir saturation-pressure dependency can be acquired from available constant volume depletion (CVD) or constant composition expansion (CCE) laboratory test results. As a result, the influence of reservoir characteristics or drawdown conditions on saturation-pressure path has not been rigorously investigated in general; and even less for the particular case of infinite-acting reservoir systems under linear flow regime, which is the most commonly observed flow regime in multi-fractured horizontal wells. In the present work, a recently developed semi-analytical solution for the multiphase black-oil formulation, which considers both pressure and liquid saturation as independent variables, is employed to investigate the influence of reservoir and well conditions on saturation-pressure path in linear infinite-acting liquid rich gas systems. Here, the effects of constant bottomhole flowing pressure, initial reservoir pressure, and relative permeability characteristics on pressure-saturation path are explored in a reservoir system. Results are compared to constant composition expansion (CCE) and constant volume depletion (CVD) tests, which are routinely invoked to estimate saturation-pressure path, and it is demonstrated that these tests provide very poor estimations of saturation-pressure path for all cases considered. In addition, saturation-pressure paths exhibit significant sensitivity to the parameters investigated, as a result of the significant interplay between liquid dropout and phase mobility. Finally, following the results of the sensitivity study, we use the concept of the compositionally-extended black-oil formulation to further study the physical mechanisms that control saturation-pressure path behavior, which are elucidated through an investigation of the in situ and flowing compositions of surface gas and surface oil pseudocomponents. The results of this paper indicate that traditional methods for estimation of the saturation-pressure path in liquid-rich unconventional systems cannot account for the influence of system parameters on liquid-phase dropout and condensate accumulation. Furthermore, production data analysis techniques must account for these dependencies to develop reliable reservoir forecasts and reserve estimations.

Examination of unconventional phenomena in naturally fractured liquid-rich gas reservoirs: single-block compositional model

During the depletion of liquid-rich gas reservoirs, the gas condenses as the pressure inside the reservoir reduces below the hydrocarbon dew-point pressure, which introduces retrograde condensate. In such conditions, the productivity experiences a reduction in recovery due to the appearance of condensate near the production channels. This work is aimed to provide insight on productivity characteristics of a liquid-rich gas system in unconventional environments and extend the scrutiny on the propagation of condensate while activating capillary forces and diffusion. The impact of capillary pressure on phase behavior was explored using an in-house generated coupled phase behavior model with a capillary pressure equation. The influence of capillary pressure was examined against different sets of composition combinations in different reservoir settings. Capillary force extents were highly dependent on composition combinations and pore throat radiuses. Mixtures with higher volatile concentrations showed the highest capillary forces. The enhancement in condensate propagation, resistance to gas flow, and impact on recovery were explored at 10- and 20-nm pore throat sizes. The investigation suggested that interfacial tensions implied greater influence on the flow behavior in oil-dominated systems than in gas-dominated conditions. Evaluating the flow performance of unconventional phenomena in liquid-rich gas reservoirs was extended to include diffusion while activating capillary forces. The results showed higher domination of diffusion on reservoir performance, which provided additional fluid recovery. Subsequently, the enhanced withdrawal of fluid dismissed the impact of capillary forces on gas flow and the impact of condensate blockage.

Characterization of carbonate mudrocks of the Jurassic Tuwaiq Mountain Formation, Jafurah basin, Saudi Arabia: Implications for unconventional reservoir potential evaluation

Organically rich mud rocks are currently targeted for unconventional oil and gas exploration and development in many places around the world, including Saudi Arabia. The Jurassic Tuwaiq Mountain Formation in the Jafurah basin, located east of the giant Ghawar oil field is the primary focus of this paper. The formation has been divided into 3 Tiers possessing varying reservoir qualities. Of these Tiers, the bottom Tier 1 possesses the most excellent shale gas characteristics such as high total organic content (TOC), low clay content and high hydrocarbon saturation. The formation of interest is also in the proper maturity window for hydrocarbon generation and relatively shallow, making it attractive for an economic unconventional shale gas play. To expedite shale gas development in Saudi Arabia, a phased de-risking strategy has been implemented. The strategy consists of four phases; exploration, appraisal, pilot and development. Three wells, representing the first unconventional reservoir exploration wells drilled in the Jafurah basin have been selected for this study. The wells were drilled vertically, cored and logged. Wells were then sidetracked with 5000 ft horizontal laterals and stimulated through multistage hydraulic fracturing. All stimulated wells flowed gas and condensate to surface. This paper summarizes, with examples, a workflow for characterizing the Tuwaiq Mountain Formation as a potential unconventional liquid rich gas play. Crucial to this, is the development of a reservoir quality predictive model for acreage grading, sweet spot identification and fracturing stage selection. This methodical approach is applicable to the evaluation of any emerging unconventional play.

Rate forecasting during boundary-dominated multiphase flow: The rescaled exponential model

Abstract Well performance forecasting is an important analytical technique used for field development to guide economic decisions during the life of a reservoir. For the case of dry and liquid-rich gas wells, traditional well performance models are developed based on solving the resultant highly nonlinear gas flow equations via pseudo-pressure and pseudo-time linearization. In this study, we provide a straightforward, density-based alternative to traditional models. We show, as done previously for the case of dry gas wells ( Ayala H. and Zhang, 2013 , Zhang and Ayala, 2014a ), that a rescaled exponential model is a rigorous decline solution that can be extended to liquid-rich gas wells producing under constant bottomhole-flowing-pressure (BHP) during boundary-dominated flow (BDF) and multiphase conditions. The proposed multiphase rescaled-exponential model is derived analytically from governing multiphase flow equations; comparisons between numerically simulated results and proposed analytical model for a variety of combinations of reservoir and fluid properties demonstrate that the proposed rescaled-exponential model is a valid and reliable forecast model for constant-BHP liquid-rich gas wells under BDF.

A density-based material balance equation for the analysis of liquid-rich natural gas systems

This study analytically cross examines the consistency among available zero-dimensional material balance equations (MBEs) for liquid-rich gas equations and derive a new simple yet rigorous MBE starting from governing equations applicable to these systems. We propose a new zero-dimensional (tank) material balance equation directly applicable to the analysis of liquid-rich (wet and retrograde) gas reservoirs expressed as a function of an equivalent gas molar density, as well as investigate and critically compare its predictions against other zero-dimensional (tank) models proposed in the past for gas reservoir cases with different amounts of condensate content (lean, intermediate and rich). All models are employed to predict reservoir performance given reservoir original-fluids-in-place and compared against benchmark examples created by numerical simulation. Actual field examples are also analyzed using existing and proposed models to test their ability to provide reliable reserve estimations using straight-line methods. The proposed density-based equation is proven to be straightforward to implement since it is written in terms of density, which allows it be directly expressed as an extension of the dry gas MBE, while not requiring the implementation of two-phase Z-factors.

An Approximate Semianalytical Multiphase Forecasting Method for Multifractured Tight Light-Oil Wells With Complex Fracture Geometry

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.

History-matching and forecasting tight/shale gas condensate wells using combined analytical, semi-analytical, and empirical methods

The primary focus of the majority of current, and foreseeable, natural gas drilling within North America is low-permeability liquid-rich gas and gas condensate reservoirs, where the liquid fraction is now a major source of revenue. Development of these liquid-rich resources is aided by the use of multi-fractured horizontal wells (MFHWs), and is at an early stage; further research is required to appropriately manage the resource for optimal hydrocarbon recovery.The appropriate forecasting methodologies to apply to these tight liquid-rich plays are a focus of current research. While numerical simulation is the most rigorous forecasting methodology, practitioners have turned to simple analytical and empirical methods because of their ease-of-use and requirement of less data. However, these analytical and empirical approaches have limitations that limit their applicability for unconventional resevoirs with complex reservoir, hydraulic fracture and fluid properties.In this study, the workflow of Clarkson (2013b) is applied to address the limitations of existing empirical and analytical methods for forecasting MFHWs producing from liquid-rich tight gas/shale. The workflow calls for constraint of analytical models by linking inputs to rate-transient analysis-derived reservoir and hydraulic fracture properties, and constraining empirical model forecasts to be consistent with analytical model forecasts. In order to address the range in reservoir/fracture properties observed in shales, a suite of analytical models is proposed. Similarly, a suite of empirical methods is used, and the models yielding the most accurate matches to the analytical models are selected for forecasting. Lastly, in order to bridge the gap between analytical and empirical methods, the semi-analytical method introduced by Clarkson and Qanbari (2015), which has as its basis the contacted gas-in-place calculations of Agarwal (2010), is also used for forecasting.An important contribution of this work is the demonstration of the applicability of the analytical and semi-analytical models used in this work for tight gas/shale gas condensate MFHWs exhibiting multi-phase flow in the reservoir. As demonstrated in this study using simulation cases, constant condensate gas ratios can occur for tight/shale gas condensate wells exhibiting transient linear flow and flowing at near constant flowing bottomhole pressure, even for relatively rich gas cases, rendering the single-phase forecasting methods useful for forecasting gas and condensate phases. The accuracy of these methods is tested using simulated cases, and practicality of the workflow demonstrated using an actual field example of a liquid-rich shale MFHW.This study will be of interest to those petroleum engineers who are faced with forecasting a large number of liquid-rich shale wells, and desire methods that can be simply applied to constrain forecasts and improve accuracy.

Petrophysical and geomechanical characteristics of Canadian tight oil and liquid-rich gas reservoirs: I. Pore network and permeability characterization

Abstract The results from an ongoing laboratory study investigating petrophysical characteristics of the Montney and Bakken formations in Canada are presented. The primary objectives are to (1) characterize the pore network (porosity, pore size distribution) and fluid transport (permeability) properties of these formations in areas with limited datasets and (2) analyze the effects of different geological factors on porosity, pore size distribution and permeability. The techniques used for characterization include: Rock–Eval pyrolysis; bitumen reflectance (BRo); grain size measurement; helium pycnometry; low-pressure gas (N2) adsorption (surface area, pore size distribution); pressure-decay profile permeability, pulse-decay and crushed-rock gas (N2, He) permeability and fracture permeability tests. Rock–Eval analysis and microscopic observations indicate that most samples are organic-lean (average TOC content: 0.3 wt.%), ranging from fine-grained siltstone to very fine-grained sandstone (grain size range: 27–53.7 μm). The measured permeability values on core plugs increase with increasing porosity (2.1–14.1%), ranging between 3.3 ⋅ 10−6 and 7.3 ⋅ 10−2 mD. For the core plugs analyzed (“as-received”), profile (probe) permeability values (9.2 ⋅ 10−4–7.3·10−2 mD) are consistently higher than pulse-decay (1.6 ⋅ 10−5–3.9 ⋅ 10−2 mD) and crushed-rock (3.3 ⋅ 10−6–4.6 ⋅ 10−5 mD) permeability values. Corrected profile (probe) permeability values for “in-situ” effective stress (5.3 ⋅ 10−5–2.5 ⋅ 10−2 mD) are, however, comparable with the pulse-decay (1.6 ⋅ 10−5–3.9 ⋅ 10−2 mD) permeability values. Unpropped fracture permeability, determined using an innovative procedure in this work, can be significantly (up to eight orders of magnitude) higher than matrix permeability under similar effective stress conditions. The grain size data are correlated to permeability values. The dominant pore throat diameter controlling fluid flow is estimated for all samples using Winland-style correlations; these values agree with those obtained from low-pressure N2 adsorption analysis. Applying multiple analysis techniques on a large number of samples (26 m of slabbed core, 22 core plugs and their accompanying cuttings), this study provides a comprehensive petrophysical characterization of Montney and Bakken tight oil and liquid-rich gas reservoirs in Canada.

Petrophysical and geomechanical characteristics of Canadian tight oil and liquid-rich gas reservoirs: II. Geomechanical property estimation

The results from an ongoing laboratory study investigating geomechanical characteristics of the Montney and Bakken formations in Canada are presented. The primary objectives are to (1) characterize the basic geomechanical properties of these formations in areas with limited datasets and (2) investigate the interrelationship between various petrophysical and geomechanical characteristics of these fine-grained tight reservoirs.For two petrophysically well-characterized core slabs from Montney and Bakken formations (Part I), mechanical hardness tests were performed using a portable Equotip® Piccolo 2 hardness tool at the same spots as profile permeability tests. For Montney core slabs, the mechanical hardness values range between 590 and 820 HLD, while for Bakken core slabs, the mechanical hardness values range between 480 and 640 HLD. The mechanical hardness data are roughly correlated to profile permeability values; permeability decreases with increasing mechanical hardness. Using mechanical hardness data and available correlations in the literature, the unconfined compressive strength (UCS) values are further estimated for the analyzed core slabs. The obtained interrelationships between mechanical hardness, profile permeability and UCS data can be used to roughly predict permeability profile and mechanical stratigraphy along the drilled core by performing simple, inexpensive, fast mechanical hardness tests.

The Use of Microseismicity To Understand Subsurface-Fracture Systems and To Increase the Effectiveness of Completions: Eagle Ford Shale, Texas

SummaryExisting natural fractures often have a significant impact on both the stimulation and the production of oil and gas wells. The effective exploitation of unconventional reservoirs requires understanding of the local tectonic history and the present-day stress regime. Signal strength; high-quality reflection seismic, microseismic imaging; and the moderate structural complexity of the liquids-rich gas and tight oil Eagle Ford Shale make it an excellent place to study hydraulic fracturing in tight rocks. Microseismic-monitoring results showed clear structural trends relating to the reactivation of existing faults and fractures, and rock-failure mechanisms determined through source mechanism inversion of events. These results provided critical information to the operator for optimizing the hydraulic-fracture design.Microseismic data collected by use of a surface array allowed the full geometry of the result to be viewed with no directional bias. The geometry of the microseismicity trends related to fracturing developed during the stimulation treatment was representative of the true geometry of the structure. The large aperture and wide azimuth of the monitoring array facilitated the determination of source mechanisms from every event detected, which provided full coverage of the focal sphere of each source mechanism. The events identified two different source mechanisms, indicating a failure mechanism for fractures that is different from that for reactivated faults.Microseismicity with a northeast/southwest (NE/SW) orientation is interpreted to be related to either induced or reactivated faults or fractures. Microseismicity also formed trends that are contiguous across more than one wellbore in an east-northeast/ west-southwest (ENE/WSW) direction. These trends are interpreted to have formed as a result of fault reactivation. Source mechanisms from fracturing parallel to SHmax have failure planes that strike NE/SW with normal dip-slip failure on steeply dipping planes. Those from fault reactivation have strike-slip failure on ENE/WSW-striking failure planes. The NE/SW-striking, dip-slip fractures are parallel to extensional Gulf of Mexico (GOM) growth faulting, and the ENE/WSW-striking, strike-slip faults are at an angle of approximately 25° to the dominant fracturing trends.Microseismicity trends associated with faults are used to project where faults will intersect adjacent wells. The identification of these faults in the reservoir by means of microseismic mapping allows operators to modify their treatment parameters and stage spacing to avoid geologic hazards. The operator combines the treatment-pump parameters for the wells with the additional structural understanding gained from the analysis of fracture trends and source mechanisms to identify zones that should be avoided in subsequent treatments. In addition, the mapped microseismicity provides critical information that was used to modify well spacing for subsequent wells, thereby optimizing the completion plan and dramatically cutting costs.