This study introduces a novel outlook on a shale-pore system and on the potential effect of pore compressibility on the production performance. We divide porosity of the system into accessible and inaccessible pores, and incorporate inaccessible pores with grains into the part of the rock that is not accessible. In general, accessible pores contribute to flow directly, whereas inaccessible pores do not.
We present a mathematical model that uses mercury-injection capillary pressure (MICP) data to determine the accessible-pore and inaccessible part of the rock (IRP) compressibility as a function of pressure. During MICP testing in a typical shale sample, the rock sample experiences conformance, compression, and intrusion as effective pressure increases. We characterize the compressibility value dependent on MICP data as a function of pressure. The calculated compressibility values for accessible pores generally appear to be much greater (two to three orders of magnitude) than those of IRP.
Next, we evaluate how calculated accessible-pore-compressibility values affect gas recovery in several shale-gas plays. Our results suggest that substitution of total pore compressibility with accessible-pore compressibility can significantly change the reservoir-behavior prediction. The fundamental rock property used in many reservoir-engineering calculations including reserves estimates, reservoir performance, and production forecasting is the total pore-volume (PV) compressibility, which has an approximate value typically within the range of 1×10-6 to 1×10-4 psi-1 (Mahomad 2014). By recognizing the part of the pore system that actually contributes to production and identifying its compressibility, we can substitute total pore compressibility with accessible-pore compressibility. The result changes the value by nearly two orders of magnitude.
The outcome of the paper changes the industry’s take on prediction of reservoir performance, especially the rock-compaction mechanism. This study finds that production caused by rock compaction is in fact much greater than what has often been regarded, which will change the performance evaluation on a great number of reservoirs in terms of economic feasibility.
ABSTRACT: The Vaca Muerta formation has been under study as a potential shale reservoir since approximately 2007; however, the first well, targeting this formation, was drilled in 2010. During the last few years, many works showing different discoveries about Vaca Muerta mechanical rock properties have been published. All of them are an invaluable piece of work; nevertheless, they do not give a full characterization of Vaca Muerta mechanical rock properties. Until today, many meters of core samples were recovered from Vaca Muerta formation and a complete set of rock mechanics laboratory tests have been performed on core plugs to accurately characterize all the parameters that governs the mechanical behavior of the rock. In addition, to further understand the variability in the mechanical response of the rock, changes in the setting up of the laboratory tests were done in similar plugs on a same core sample (sister samples). It is the aim of this paper to present an overview of recent Vaca Muerta research works which include mechanical laboratory characterization of the rock and discuss about how different laboratory test parameters such as temperature, confining pressure, time, and fluid saturation among others affects the mechanical response of the rock. To complete the understanding of the Vaca Muerta formation mechanical behavior, special laboratory studies like Biot's coefficient and creep test were performed in some core shale gas samples; nevertheless, in this work, the quality and validity of these results are left as an open discussion. The most important conclusion of the analysis done in this work is that some elastic properties are not mainly controlled by the “rock families or facies”. As a result, a unique correlation between many elastic properties has been found and a simple workflow to fully characterize the rock mechanical properties of Vaca Muerta formation is proposed.
During the exploration, delineation and development of the principal shale oil and gas reservoirs in Argentina, several studies like petrophysics, geochemistry, biostratigraphy and geomechanics haves been done. In order to calibrate the parameters of different models many meters of core has been recovered from the Vaca Muerta formation in the Neuquén basin, Argentina. This core acquisition was fundamental for the correct characterization of the mechanical rock properties. These properties play a fundamental role in every stage in the life of a well i.e. drilling process (wellbore stability), fracturing process and finally production forecasting.
The Cline shale in the Midland Basin is an organic rich mudrock comprising the Cisco and Canyon Groups which has recently become an exploration target and production interval. The Cline is interpreted to have been deposited in a deep water environment by hemipelagic suspension and mass transport processes varying from debris flow to turbidity flow. Based on core description, thin section observation, and bulk compositional XRD data carried out on seven cores, seven lithofacies have been identified including various types of mudstone, carbonate and sandstone. Over 500 wireline logs were used to correlate and divide the stratigraphy of the Cline Interval. Regional stratigraphic sections show that the Cline dips towards the Central Basin Platform and ranges from 117 ft to 530 ft in thickness.
Gamma-ray log patterns can indicate sea level fluctuation and lithology stacking patterns by responding to clay content and organic matter. Two types of stratigraphic cycles are identified in the Cline Shale of the Midland Basin: shallowing-upward cycle and deepening-upward cycle, which are illustrated by two types of gamma-ray patterns: upward-increasing trend and upward-decreasing trend. Fifteen stratigraphic cycles have been distinguished from a typical basinal core, where eight are in the Lower Cline and seven are in the Upper Cline. These cycles are laterally continuous across the basinal area. More stratigraphic cycles can be recognized near the toe of slope, because not all depositional events extend across the basin floor. We infer from cyclicity correlation that high-frequency sea-level fluctuation and regional tectonism affected depositional processes on the platform and controlled sediment deposition in the basin.
The Cline shale is an unconventional resource play containing Type I, Type II and Type III kerogen. Total organic carbon (TOC) ranges from 0.13% to 9.88%. The Cline is currently at the oil window, and some areas have entered early condensate gas window. Lab-measured dry helium porosity averages at 5.75%. Massive argillaceous and siliceous mudstones contain relatively higher TOC and porosity and may act as both source rocks and reservoir rocks. These two facies are more prevalent and continuous in basinal areas within shallowing-upward cycles, providing indications for locations of potential pay zones.
Hydraulic fracturing is crucial to hydrocarbon recovery from resource plays and is essential to exploitation of geothermal energy. This process creates new tensile fractures and reactivates existing natural fractures, forming a highly conductive stimulated-reservoir volume (SRV) around the borehole. Although this process has been extensively studies and modeled for isotropic rock, only a limited number of studies have been performed for anisotropic rocks, such as shales, gneisses, and foliated granites. The fracturing process of anisotropic rocks such as shales is examined in this study. We divide the rock anisotropy into two anisotropic groups: conventional and veined. Two members of the conventional first group are Lyons sandstone, a brittle, quartz-dominated, low-porosity and -permeability, anisotropic (11%) material; and pyrophyllite, a monomineralic-clay-rich, strongly anisotropic (19%) metamorphic rock similar chemically and mechanically to shale with extremely low porosity and permeability. The second group consists of a suite of natural shale samples (18% anisotropy) from the Wolfcamp formation containing mineralized veins. Fracture initiation and propagation are studied during Brazilian tests. Strain gauges and acoustic-emission (AE) sensors record the deformation leading to and during failure. Scanning-electron-microscope (SEM) imaging and surface profilometry are used to study the post-failure fracture system and failed surface topology. Post-fracture permeability is measured as a function of effective stress. The influence of anisotropy on fracturing is investigated by rotating the sample-fabric direction relative to the loading axis through increments of 15°.
The rock microstructure, lamination, and brittleness control the activation of the layers. Lyons sandstone shows a wide brittle fracture with larger process zone with twice as much layer activation at lower stress levels than pyrophyllite. The fracturing process in veined shale is, however, a coupled function of rock fabric and mineral veins. The veins easily activate at 15° orientation with respect to the loading axis at stress levels of 30% of the unveined-failure load. The resulting unpropped fracture has enhanced permeability by orders of magnitude. We suggest that fracturing from a deviated well reduces the breakdown pressure significantly (compared with a vertical well) and activates a large number of veins with enhanced conductivity without the need for excessive proppant.
The goal of this study was to compare constitutive parameters derived from short-term (four hour) and long-term (several-week) creep experiments. We conducted a series of creep experiments on clay and carbonate-rich shale samples from unconventional gas and oil reservoirs at room temperature, principally on samples from the Haynesville and Eagle Ford formations. Samples with different mineralogies were subjected to a series of multi-stage loading/creep, unloading/recovery cycles conducted over different time spans. All creep stages of the experiments were performed at a constant differential stress level; only the testing time of each creep/recovery stage was varied. Following Sone and Zoback (Jour. Petrol. Sci. and Eng., 2014), a power-law creep model was used to obtain the creep constitutive parameters. Results of these experiments show that the shale samples follow the same creep trend through time, regardless of the loading history. Also, we show that the simple power-law model is capable of describing creep over multiple time periods. Using this model, we are able to characterize viscoplastic behavior of shale rocks from relatively short-term (1 day) creep experiments.
A common challenge in laboratory creep studies is to know how long laboratory experiments need to be carried out to accurately measure the parameters that make it possible to predict rock deformation over relatively long periods of time. This time-dependent deformation affects mechanical and flow properties of sedimentary rocks [1, 2, 3, 4, 5, 6]. Initial laboratory studies of viscoplatic deformation were carried out via uniaxial and triaxial creep experiments [7, 8, 9, 10]. Because of the time-consuming nature of these experiments, relatively few papers have addressed this topic.
In this paper we carried out a series of creep experiments on shale samples with various amounts of carbonate and clay to investigate the constitutive law and creep parameters obtained in loading steps ranging from several hours to several weeks. We extend the comprehensive short-term (several hour) creep experiments reported by Sone and Zoback (2014) who investigated the role of clay and organic content on viscous deformation of shales from unconventional gas reservoirs . They used a relatively simple (two parameter) power-law model to fit the data.
Several mechanisms have been proposed to explain low temperature creep in sedimentary rocks. Although Peterson and Wong (2004) argue that the deformation of rocks at temperatures below 1200 K can generally be considered brittle , other studies have shown that it is possible to observe inelasic deformation of rocks at lower temperatures due to mechanical compaction processes . For example, Sone and Zoback (2014) argued that the time-dependent deformation they observed was accommodated by changes in the pore volume.
Yue, Kaimin (Petroleum and Geosystems Engineering, The University of Texas at Austin) | Olson, Jon E. (Petroleum and Geosystems Engineering, The University of Texas at Austin) | Schultz, Richard A. (Petroleum and Geosystems Engineering, The University of Texas at Austin)
Oil and gas production from unconventional reservoirs requires drilling and hydraulic fracturing within a layered reservoir, which is usually stratified with a variety of stiff and soft layers. The overall strength of layered rocks is useful for predicting their stability or failure under production conditions, which may contribute to vertical height containment of hydraulic fractures in an unconventional reservoir. In this work, triaxial experimental testing of reservoir-analog materials and three-dimensional Particle Flow Code (PFC3D) simulations were used to evaluate the contributions of layer properties, such as number, thickness, and sequence, on the average strength of a layered reservoir.
The laboratory and PFC simulation results show that the stiffness and strength of a layered sequence are not affected by factors such as bedding plane strength, the number of layers, or layer thickness. However its stiffness and strength can be related to the relative proportions of stiff and soft layers. The stiffness of the layered sequences obtained from the experiments and PFC models are closely predicted by a calculated harmonic average stiffness of the sequence. The stiffness-strength relation obtained from the reservoir-analog materials has a similar form to those in the literature that were obtained from natural rock types, supporting the utility of PFC models of layered sequences. These results support the use of harmonic average and PFC simulations in estimating elastic stiffness and strength in layered and unconventional reservoir sequences.
Oil and gas production from unconventional reservoirs generally requires hydraulic fracturing within a layered reservoir, which is usually stratified with layers of different mechanical properties. For instance, Eagle Ford shale is a well laminated reservoir with alternating stiff carbonate rich layers and soft clay rich layers . In order to produce hydrocarbon from unconventional reservoirs more efficiently and economically, a better understanding of hydraulic fracture propagation in layered reservoirs is needed. Among all the issues, vertical height growth of hydraulic fractures is recognized as one of the critical factors to the success of hydraulic fracturing treatments [2, 3]. If the expected hydraulic height growth is not achieved, a large area of payzone will not be stimulated which affects the production. In contrast, if hydraulic fractures grow into the adjacent rock layers which are not productive, an excessive amount of injection fluid and proppants will be wasted .
To fully characterize geomechanical properties of a vertically transverse isotropic (VTI) medium, such as shale, five independent stiffness coefficients are required. However, only three can be measured through sonic log measurements. This gap has traditionally been filled by applying the ANNIE model. One of the critical assumptions in the ANNIE model causes vertical Poisson's ratio to always be greater than horizontal Poisson's ratio and predicts the anisotropic and isotropic stresses to be equal. However, these assumptions are usually not the case in unconventional reservoirs.
A modified-ANNIE (M-ANNIE 1) model helps overcome the limitations of the ANNIE by introducing two empirical multipliers. However, both the ANNIE and M-ANNIE 1 models require Stoneley wave velocity as input, which prevents their applicability in cased-hole conditions or conditions with no advanced sonic logging tools.
Recently, two new methods, velocity regression (V-reg) model and a further modified ANNIE model (M-ANNIE 2), were proposed to predict the stiffness coefficients independent of the Stoneley wave. It is observed that the simple generic relationships derived from core ultrasonic data are not sufficient for stiffness coefficients characterization.
Ultrasonic velocities were measured on whole cores from a North American shale play in 0, 45, and 90° orientations to obtain direction-dependent compressional (Vp) and shear waves (Vs) velocities. Different anisotropic acoustic models were applied to compare their prediction capacity and limits. This study includes more laboratory data, such as X-ray diffraction (XRD) mineralogy and total organic carbon (TOC), to provide a lithological context. It was observed the shale has a large portion of carbonate (> 80v%), and its acoustic anisotropy indicator Thomsen parameters, epsilon and gamma, are strongly related to clay and kerogen content. This paper discusses how the high carbonate content alters the previously established generic models for M-ANNIE 1, 2, and V-reg. The paper also investigates the relationship between the dynamic and static elastic moduli interpreted from the ultrasonic and triaxial data, respectively. The dynamic and static data were used to fit widely used dynamic-to-static conversion equations: the Canady and Morales equations. The Canady equation was extended to the “very hard” (greater than 70 GPa Young's modulus) regime, while the Morales equation was extended to the regime of less than 10% porosity. Next, the calibrated dynamic Young's modulus is also used to estimate the unconfined compressive strength (UCS). The prediction qualities of different acoustic anisotropic models are investigated.
As compared with the conventional ANNIE and isotropic models, the lithology-based anisotropic acoustic models (M-ANNIE 1, 2, and V-reg) highly improve the predictions of the stiffness coefficients and elastic moduli; hence, they provide better predictions of the minimum horizontal stress. Accurate predictions of elastic moduli and stress are crucial for selecting proper drilling mud, cement weights, and drilling/perforation locations.
Yang, Liu (China University of Petroleum) | Ge, Hongkui (China University of Petroleum) | Shen, Yinghao (China University of Petroleum) | Ren, Kai (China University of Petroleum) | Sheng, Mao (China University of Petroleum) | Gao, Zhiye (China University of Petroleum) | Qin, Xiaolun (China University of Petroleum) | Su, Shuai (China University of Petroleum)
Field researches conducted on the multi-stage hydraulic fracturing measurements manifest that a large proportion of fracturing fluid retains in tight reservoirs, and the flow-back efficiency is usually lower than 30%. The publications have demonstrated that the spontaneous imbibition plays a significant role in large volumes of water loss, which is caused by high capillary pressure of tight rocks. Nevertheless, the imbibition characteristics of tight rocks are quite complex and still need further research owing to the complex pore structure, mineral constituent and strong microscopic heterogeneity.
Comparative imbibition experiments were carried out on 12 core samples, which are seclected from tight sandstone formation from Ordos Basin, tight volcanic formation from Songliao Basin and shale formation from Sichuan Basin. Hence, a new method is proposed to demonstrate the imbibition characteristics and estimate fracturing fluid intake in tight gas formation. Moreover, the authors study the water imbibition capacity and characteristics of tight rocks, which holds diverse mineralogy, pore-size distribution and pore connectivity. The experimental data of tight rock samples in different size and shape can be normalized by using the new characterizing method, which exhibits the imbibition capacity, initial imbibition and late imbibition rate. The imbibed water volume increases with the clay content, and smectite and illite/smectite tends to strong water imbibition. Due to the water absorption on clay surface, the ratio of imbibed water volume to pore volume measured by Helium exceeds 100%. In addition, a general observation shows that each imbibition curve of tight rock can be divided into an initial imbibition region, a non-linear transition region, and a late imbibition region. However, the imbibition characteristics of different tight rocks vary greatly, which could be attributed, at least in part, to the complex pore connectivity, pore-size distribution and mineral composition. Well-developed macropores tend to have well pore connectivity and large time exponent at the initial imbibition region. Well-developed mesopores and micropores tend to have poor pore connectivity and large time exponent at the late imbibition region. These studies can be used to evaluate the fracturing fluid imbibition characteristics, and to understand its relationship with pore connectivity and pore-size distribution in tight reservoir rocks.
Unconventional reservoirs (UNC) are considered those that do not produce at economic flow rates and cannot be cost-effectively produced without applying stimulation, fracturing, and recovery. They are located in predominantly extensive regional accumulations, which, in most cases, is independent of the stratigraphic and structural traps. This requires using special technology for extraction, either by its oil properties or the characteristics of the rock that contains it.
Today, these reservoirs represent an interesting source of income, because many of them are found in deposits that were considered to be exhausted or non-economic by traditional recovery methods, and it is estimated that they are present in large volumes. The recently exploited shale plays are typically constituted by a matrix of very fine grain rock (size clay, shale or marl might be), with varying proportions of clay, silica, and carbonate, which act as source rock, and reservoir seals at the same time. They have very low permeability and often require massive stimulation to produce hydrocarbon.
Generally, resource shale reservoirs must meet a series of requirements to make them economically viable. These conditions are: Organic richness (> 2% COT for shale gas and shale oil variable) Thermal maturity (> 0.7% Ro) Thickness (> 30 m) and areal extent Adsorption capacity (mainly in shale gas) Fracturability (clay content < 40%) Overpressure Depth Surface facilities
Organic richness (> 2% COT for shale gas and shale oil variable)
Thermal maturity (> 0.7% Ro)
Thickness (> 30 m) and areal extent
Adsorption capacity (mainly in shale gas)
Fracturability (clay content < 40%)
Do fractures help or hinder production in hydraulically stimulated resource plays? Most say they help, but some say they hinder. After monitoring productivity for over 10 years in a number of plays in Shell's unconventional portfolio, it appears that the evidence for fractures helping is more conceptual than empirical, further substantiated by a detailed literature review. The objective of this paper therefore is to bring some objectivity to the discussion around the impact of structure using logical arguments by reason, incorporating knowledge of the variability in structure and well performance within the spectrum of unconventional plays.
Fundamental to this assessment is the recognition that different scales of features will have a markedly different impact. And to communicate the concepts herein, small-scale features are referred to as "natural fractures" and large-scale features, referred to as "faults" or "lineaments".
This analysis indicates that the variability in (small-scale) natural fracture intensity across most plays is not sufficient to be detected in well performance metrics, given the other sub-surface heterogeneity and the large range in estimated ultimate recovery (EUR) for any given set of wells. Furthermore, natural fracture connectivity is typically low and stimulation of networks is not supported by data or trials. It is proposed to consider natural fractures as an intrinsic rock property which will modify the bulk geomechanical properties of the formation. The only exception found was for folded tight-sand plays, where fracture network connectivity may be sufficient to provide a measurable enhanced deliverability.
Understanding the impact of seismically-visible, planar, structural features (e.g. faults or lineaments) proved to be more problematic, with operators reporting both EUR increases and decreases. This inconsistency is explained with a novel concept classifying faults as
Rather than searching for a production performance correlation, it is suggested that an enhanced understanding of the physical processes during a hydraulic stimulation would be more beneficial to clarify the impact of structure. And to this aim, a compilation of potential fracturing diagnostics is presented herein.