Heavy oil is defined as liquid petroleum of less than 20 API gravity or more than 200 cp viscosity at reservoir conditions. No explicit differentiation is made between heavy oil and oil sands (tar sands), although the criteria of less than 12 API gravity and greater than 10,000 cp are sometimes used to define oil sands. The oil in oil sands is an immobile fluid under existing reservoir conditions, and heavy oils are somewhat mobile fluids under naturally existing pressure gradients. Unconsolidated sandstones (UCSS) are sandstones (or sands) that possess no true tensile strength arising from grain-to-grain mineral cementation. Many heavy oil reservoirs are located in unconsolidated sandstones.
The reporting of potential resources is essential to assess the future development plan and profitability of a petroleum discovery, but if the project is under appraised and production data are absent, analysts often use analogs for preliminary estimates of technically recoverable volumes. To address this, a workflow is presented for selecting appropriate analogs for unconventional plays and using them to estimate the target play's potential. The proposed technique is demonstrated with a case study of the as-yet undeveloped Bowland Shale, which is the most prominent of the shale plays in the United Kingdom (UK) and is at the early stage of its assessment. The paper describes the current shale gas activity in the UK, highlighting the enviromental constraints placed on would-be Bowland Shale developers, which impact on drilling and production operations and stem from the geographic proximity of urban developments, infrastructure and nature, which limit the size of well pad footprint in the UK where land use is high. Studies have estimated the play's in-place resources for possible future development, but there are few estimates of its corresponding recoverable volumes due to lack of production history. At the outset, a database is created with published minimum-average-maximum ranges of key parameters such as total organic carbon, maturity level, gas filled porosity, permeability, etc. that play a major role in resources estimation and recovery potential for all unconventional plays. A comparison of triangular distributions, key parameter by key parameter, between the target shale play and the analog database, is then carried out using novel graphical and statistical methods to establish a "confidence factor" relating to the analog's viability. The most appropriate analog for the Bowland Shale is chosen from an exhaustive list of North American shale gas plays. Analytical approaches are then used to transform a model of the published type well performance of the selected analog by exchanging key model parameters with those of the target shale play. The paper shows how UK operational constraints can be statistically incorporated into the workflow and have a marked effect on the estimated recovery from the Bowland Shale.
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Cao, Jinrong (The University of Tokyo) | Liang, Yunfeng (The University of Tokyo) | Masuda, Yoshihiro (The University of Tokyo) | Koga, Hiroaki (Japan Oil, Gas and Metals National Corporation) | Tanaka, Hiroyuki (Japan Oil, Gas and Metals National Corporation) | Tamura, Kohei (Japan Oil, Gas and Metals National Corporation) | Takagi, Sunao (Japan Oil, Gas and Metals National Corporation) | Matsuoka, Toshifumi (Fukada Geological Institute)
In this paper, we present an improved method to predict the methane adsorption isotherm for a real shale sample using molecular dynamics (MD) simulation with a realistic kerogen model. We compare our simulation results both to the experiment and to the simulation results on the basis of a simple graphite model, and show how our procedure leads to the creation of more accurate adsorption isotherms of a shale sample at a wide range of pressure. A Marcellus shale sample was chosen as an example to demonstrate how to calculate the adsorption isotherms using MD simulations. Type II kerogen molecular model was selected for the dry gas window. The constructed bulk kerogen model contains mesopores (> 2 nm) and micropores (≤ 2 nm) inside. Ten different mesopore sizes of kerogen nanopore systems were constructed. According to the characteristics of methane density distribution in the simulation system, three regions can be clearly distinguished, free gas, adsorbed gas, and absorbed gas. We show that the adsorbed gas per unit pore volume increases with the pore size decreased. This is similar to previous molecular simulations with graphite model. For predicting the total adsorption isotherm of a real shale sample, both adsorbed and absorbed gas were considered. For the adsorption amount, the calculated adsorption isotherms were averaged based on pore size distribution of that Marcellus Shale sample. For nanopores smaller than 5 nm, we used total organic carbon (TOC) data to weight the absorption contribution in the kerogen bulk (i.e. inside the micropores). The total adsorption isotherm thus obtained from our simulations reproduced experiments very well. Importantly, kerogen model has overcome the difficulties of prediction using graphite models (i.e. an underestimation of adsorption under high pressure conditions) as documented in previous studies. Furthermore, we predicted the adsorption isotherms for higher temperatures. With the temperature increased, lower adsorption amount is predicted. The novelty of our improved method is that it is able to predict methane adsorption isotherm at a wide range of pressure for a shale sample by considering both adsorption in kerogen mesopores and absorption in kerogen bulk. It can be readily used for any shale sample, where the pore size distribution, porosity, and TOC are known. We remark that the above results and conclusion resulted from our simple assumption. Further discussion might be necessary.
The course will discuss the Huff-n-Puff gas EOR process specifically, but will also give a background in the relevant fundamentals of gas EOR methods (miscibility, vaporization, and displacement). Alternative EOR methods will also be discussed. The course is introduced by an industrywide summary of ongoing gas EOR projects in North American unconventionals.
The water recovered from hydraulic-fracturing operations (i.e., flowback water) is highly saline, and can be analyzed for reservoir characterization. Past studies measured ion-concentration data during imbibition experiments to explain the production of saline flowback water. However, the reported laboratory data of ion concentration are approximately three orders of magnitude lower than those reported in the field. It has been hypothesized that the significant surface area created by hydraulic-fracturing operations is one of the primary reasons for the highly saline flowback water.
In this study, we investigate shale/water interactions by measuring the mass of total ion produced (TIP) during water-imbibition experiments. We conduct two sets of imbibition experiments at low-temperature/low-pressure (LT/LP) and high-temperature and high-pressure (HT/HP) conditions. We study the effects of rock surface area (As), temperature, and pressure on TIP during imbibition experiments. Laboratory results indicate that pressure does not have a significant effect on TIP, whereas increasing As and temperature both increase TIP. We use the flowback-chemical data and the laboratory data of ion concentration to estimate the fracture surface area (Af) for two wells completed in the Horn River Basin (HRB), Canada. For both wells, the estimated Af values from LT/LP and HT/HP test results have similar orders of magnitude (approximately 5.0×106 m2) compared with those calculated from production and flowback rate-transient analysis (RTA) (approximately 106 m2). The proposed scaleup procedure can be used as an alternative approach for a quick estimation of Af using early-flowback chemical data.
The volume of hydrocarbons contained in tight petroleum reservoirs is immense. Thus, their development is crucial to satisfy the worldwide energy demand. A critical aspect for the development of these formations is the stress dependency of rock properties. As pore pressure changes, porosity, permeability, and compressibility of both matrix and natural fractures in tight reservoirs also change, affecting the wells’ production behavior.
A practical problem in the estimation of stress-dependent properties is that the amount of core data available to perform the corresponding studies in tight formations is generally scarce. Under these circumstances, drill cuttings can be used to obtain this information. These observations lead to the key objective of this paper: to develop a reliable approach for estimating stress-dependent properties through the introduction of an innovative methodology that quantifies changes in properties of tight reservoirs and how to extend this methodology in drill cuttings.
The model developed is based on the relationship between the cube root of normalized permeability and the logarithm of net confining stress defined as confining pressure minus pore pressure applied on the rock. An empirical exponent α is introduced to fit the experimental data from confining tests conducted on both vertical and horizontal core samples. This exponent allows the development of an equation that works independently of the initial net confining stress, which is the main limitation of the models already available in the literature. It is our experience that, in many instances, laboratory tests are run at specific values of net confining stress that do not necessarily match the current stress of the reservoir. The correlation proposed in this paper is valuable because it provides a tool that allows correcting the laboratory results to the appropriate net confining stresses in the reservoir. A statistical analysis is performed to verify the appropriateness of the proposed model for the prediction of rock properties as a function of net confining stress.
It is shown that current formulations are particular cases of the proposed model based on the results obtained for the empirical exponent α. Semilog cross-plots of the cube root of normalized permeability versus the net confining stress using core laboratory data corroborate the robustness of the proposed method. The application of the method with drill cuttings is also demonstrated.
It is concluded that the proposed method provides a more accurate methodology for estimating stress-sensitive properties of rocks in tight formations, which are usually naturally fractured, such as the Nikanassin formation analyzed in this work. Porosity, permeability, and compressibility of tight formations are estimated by following the generalized methodology proposed in this study.
This paper will benefit engineers and geoscientists interested in creating representative hydraulic fracture simulation models and optimizing commercial-scale fracture treatments. The paper focuses on the emerging Duvernay shale formation in Alberta, Canada. Well fracturing pressures are often significantly higher than the Overburden (OB, lithostatic) pressure. Pressures above OB likely create horizontal (hz) bedding plane fracture components since sedimentary rocks are almost always weaker along bedding planes. Most fracture design simulators do not account for the simultaneous existence of multi-plane fractures (
DFIT analysis techniques and interpretation are hotly debated topics of late. The authors believe a portion of the gap in the understanding of how hydraulic fractures behave is a result of assuming fracture components are fully, or dominantly, vertical. Analysts often interpret high fracturing pressures as tortuosity or near-well friction. However, during the fall-off period after pumping a DFIT, pressures above OB can persist for up to 20 minutes after pump shut-down. Analysis of these tests often exhibit early-time radial flow signatures which are coincident with the OB gradient of ~22kPa/m (1psi/ft) also indicative of hz plane fractures. In
In the current paper DFIT PTA analysis is applied to two West Shale Basin Duvernay datasets. A physical model is presented (
Does the sub-surface drive completion design or is the rock less of a concern with industry trends to higher proppant-, fluid- and stage-intensities? To address this challenge it was first necessary to understand; 1) how the sub-surface could potentially influence completion and stimulation design, 2) what are the available engineering levers and moreover, 3) whether well performance has actually been impacted by tailoring completions in different plays from specific case-studies.
Although there is a multitude of published field examples of how completion design changes have driven value, clarity around the inter-connectedness with sub-surface variability, either between plays or within a play, is commonly missing. New templates have been developed that describe the conceptual links between the nine key 'Sub-surface Drivers' for hydraulic fracturing and their associated engineering Levers categorized by well-, fluid-, proppant- and stage-design. These templates are a compilation of extensive empirical observations from both operations and field performance reviews incorporating thousands of wells across North America, supported with learnings from geomechanical theory and modeling.
The nine Sub-surface Drivers that influence completion design and control the access to hydrocarbons are, 1) mobility, 2) reservoir pressure, 3) gross thickness, 4) layering heterogeneity, 5) rock stiffness, 6) natural fractures, 7) stress anisotropy, 8) risk of fraccing faults and, 9) risk of fraccing out of zone. Drivers 1-7 govern the connectivity, whereas 8 and 9 influence stimulation ineffectiveness. It is proposed that there are approximately fifteen primary engineering Levers related to these nine Drivers, which have been shown to have a measurable impact on completion effectiveness and/or production.
Case studies illustrate that the Sub-surface Drivers play a significant role in most plays, but they are not all relevant in every play. The challenge is to acknowledge the variability, or lack of, and pursue completion design optimization goals, while managing the variance in the well performance range.
Whereas industry trends of increasing completions intensity have delivered more value in many plays, the Sub-surface Drivers concept have primarily proven useful to mitigate against poor wells in development and explain exploration failures. By developing a systematic set of templates for Drivers and their respective levers, learnings from other operators can be high-graded through the formulation of connectivity analogues with the goal of showing where changes in completion design may be more, or less applicable.
Many stimulated shale-gas wells experience surprisingly low fracturing-fluid recoveries. Fracture closure, gravity segregation, proppant distribution, and shut-in (soaking) time have been widely postulated to be the contributing factors. This study examines the effects of these factors on fracturing-fluid distribution and subsequent well performance using flow and geomechanical simulations. In the end, two real-field examples are used to validate the findings in this study.
Geomechanical simulation is used to capture the complex post-closure fracture geometry caused by nonuniform proppant distribution. The geometry is then passed into a series of 3D numerical flow models that are constructed using petrophysical parameters, fluid properties, and operational constraints representative of the Horn River shale-gas reservoir. Within the flow simulation, the hydraulic fracture is represented explicitly in the computational domain by means of local-grid refinement, and the physical process of fracture closure during shut-in and production periods is modeled by adjusting the fracture volume and fracture conductivity dynamically. Non-Darcy behavior caused by high gas velocity in the fracture and matrix desorption are considered. The results of the geomechanical simulation confirm the formation of a residual opening above the proppant pack in a partially propped fracture. The residual opening offers a highly conductive flow path for the gas, which is much more mobile than the water-based fracturing fluid, and this difference in mobility further aggravates gravity segregation. Gravity segregation might lead to water accumulating near the bottom of a vertical planar fracture, but reduced fracture conductivity could limit the segregation and promote a more uniform fluid distribution. Water uptake into the matrix is influenced by forced and spontaneous imbibition caused by the large pressure differential across the matrix/ fracture interface and matrix capillarity. Additional water is displaced into the matrix as pressure depletes and the fracture closes. Fracturing-fluid-penetration depth increases with shut-in time, resulting in an enhancement in the initial gas rate, but lower late-time production is also observed.
Analysis of the residual opening of a partially propped fracture and its role in fracturing-fluid distribution in three dimensions is novel. Field examples suggest that considering the various physical mechanisms investigated in this study could improve the accuracy of the numerical model for history matching and the reliability of the ensuing production forecasting. The findings in this study might provide a better understanding of fracturing-fluid distribution, which is useful for optimizing production strategies and operations concerning hydraulically fractured shale-gas reservoirs.