As defined by the U.S. Federal Energy Regulatory Commission (U.S. FERC), low-permeability ("tight") gas reservoirs have an average in-situ permeability of 0.1 md or less. Others have placed the upper limit at 1 md. Estimates of ultimate recovery from these resources vary widely and depend chiefly on assumptions of wellhead gas price. Methods for estimating gas reserves in moderate- to high-permeability reservoirs are unreliable in very-low-permeability reservoirs. The unreliability can be attributed to the geologic setting in which these reservoirs occur and the completion methods required to make them commercial.
Actually, the definition of a tight gas reservoir is a function of many factors, each relating to Darcy's law. The main problem with tight gas reservoirs is that they do not produce at economic flow rates unless they are stimulated--normally by a large hydraulic fracture treatment. Eq. 7.1 illustrates the main factors controlling flow rate.
Tight gas is the term commonly used to refer to low permeability reservoirs that produce mainly dry natural gas. Many of the low permeability reservoirs that have been developed in the past are sandstone, but significant quantities of gas are also produced from low permeability carbonates, shales, and coal seams. Production of gas from coal seams is covered in a separate chapter in this handbook. In this chapter, production of gas from tight sandstones is the predominant theme. However, much of the same technology applies to tight carbonate and to gas shale reservoirs. Tight gas reservoirs have one thing in common--a vertical well drilled and completed in the tight gas reservoir must be successfully stimulated to produce at commercial gas flow rates and produce commercial gas volumes. Normally, a large hydraulic fracture treatment is required to produce gas economically.
The objective of the project is to reconcile and quantify the impact of geological and completion variables that cause significant EUR differences in two recent wells drilled and completed in the Uteland Butte member of the Green River formation in Uinta Basin, Utah. While the geology and reservoir conditions are similar for both wells, the completion design and parameters are different (Ball-and-Sleeve vs. Plug-and-Perf, job size, treatment rates, well length, etc.).
The Asset Team uses a structured workflow consisting of several modeling tools: Rate-Transient-Analysis (RTA), Frac Modeling (FM) and Reservoir Simulation (RS) to address and quantify the impact of each variable: Job size, Treatment Rate, Frac count per Stage, Well Length and the effect of clays.
The workflow began with a performance evaluation of the high EUR well (Plug-and-Perf, large job) with RTA and Frac modeling; followed by history-match and prediction of the EUR with the RS model. In the subsequent workflow, a single variable is changed in each modeling step, while others are held constant -- as such, the EUR impact for each variable can be quantified. The result from each step is calibrated with the actual performance observed in the field.
This model-based approach successfully quantified the production impact of each variable. Subsequently, the key drivers can be determined which explains the estimated EUR difference between the two wells. This work drives us to conclude that due to varying pressure, PVT and lithology across the field, different completion designs shall be utilized. The team has gained valuable insight on how to implement different completion techniques with varying job size and design for the basin. Currently, these results are used to drive the well designs and approval; with the long-term objective of optimizing the Field Development Plan.
Cudjoe, Sherifa (University of Kansas) | Barati, Reza (University of Kansas) | Marshall, Craig (University of Kansas) | Goldstein, Robert (University of Kansas) | Tsau, Jyun-Syung (University of Kansas) | Nicoud, Brian (Chesapeake Energy) | Bradford, Kyle (Chesapeake Energy) | Baldwin, Amanda (Chesapeake Energy) | Mohrbacher, David (Chesapeake Energy)
Microscopic analysis including transmitted light, UV epifluorescence, BSE, and FIB-SEM carried out on Lower Eagle Ford (LEF) shale samples, selected from similar depths, show complex depositional fabrics, kerogen, migrated organic matter, and diagenetic history. It is well known that LEF samples contain depositional kerogen and migrated organic matter. Much of the migrated organic matter occupies diagenetically reduced primary porosity. Some of this organic matter is not porous, while some contains large pores and other contains a fine network of nanopores. Where thermal maturity is one control on porosity in organic matter, there is also a control of composition and origin. This paper investigates the chemistry of organic matter in-situ using Raman spectroscopy, to begin to understand what, other than thermal maturation, leads to porosity in both depositional kerogen and migrated organic matter. This is used to evaluate the nature of the pores in LEF, and to assess the impact of hydrocarbon gas injection on organic porosity.
Thin sections of the lower Eagle Ford shale samples are examined with transmitted light microscopy to select samples for Raman spectroscopy, after studying with FIB-SEM to analyze distribution of porosity in organic matter. In the Raman spectra, the separation between the D and G bands, the width of the G-band, and the intensity ratio of the D-to-G-bands are typically ascribed to maturity-related changes. However, composition and origin of the organic matter may also have an effect. The Raman spectra are analyzed to characterize the different types of porous and non-porous organic matter at the same depth. Then, samples are subjected to gas injection in the laboratory in preparation for a gas huff-n-puff operation, and changes in Raman spectra are analyzed once again.
BSE images show depositional kerogen is found as isolated bodies, lamellar forms, and fine material disseminated in the matrix. Transmitted light and UV microscopy reveal that some of this is non-fluorescent and some is fluorescent. Cement-reduced intraparticle pores, other primary pores, intercrystalline pores, and micro-fracture and micro-breccia pores contain migrated organic matter (OM), none of which fluorescences in UV. FIB-SEM images show the migrated OM has either spongy nanopores, larger bubble/meniscate pores, or no pores, all in the same sample. Raman spectroscopy analysis on the different types of organic matter show examples where both G- and D- bands are visible with distinctive separation, intensity ratio, or width, or where the D-band is absent. Moreover, the effect of gas injection on the different types of organic matter is inferred from the G- and D- bands.
This work improves our understanding of organic pore generation and modification, which influences pore size distribution and pore tortuosity, the underlying factors in gas huff-n-puff recovery in shales. It expands the utility of Raman micro-spectroscopy as a tool in understanding the evolution of pore systems and organic constituents in shale. It also presents an in-situ molecular structural study of the effect of hydrocarbon gas huff-n-puff on the different types of organic matter.
Constant confining pressure (CCP) tests and constant effective stress (CES) tests were widely conducted to measure shale permeability. The permeability data were explained by two types of permeability models, including apparent permeability models based on the slippage effects and poroelastic permeability models based on effective stress. In these experiments and models, the basic assumption is that the slippage effects, effective stresses and gas sorption-induced matrix swelling/shrinking are the reasons that cause shale permeability change, and they could be separated and investigated individually.
In order to see if this basic assumption was appropriate, we collected shale experimental permeability data measured under the CCP and CES conditions; as well as their comparison with solutions of the poroelastic theory and the apparent permeability theory, respectively. A conceptual model of shale permeability evolutions was built. It's found that for both CCP and CES tests permeability ratios are primarily determined by the transient effective stresses in shale with well-developed macro-fractures, or the slippage effects and the transient effective stresses in shale with less-developed macro-fractures. For shale samples with the effective flow radius of pores is smaller than 5μm (initial pore pressure=1.0MPa), the apparent permeability theory can be used to explain the permeability. The permeability ratio is bounded by an upper envelope which is corresponding to the combined solution of free-swelling and slippage effects (with the increase of pore pressure the k/k0 first<1 then rebound to >1 for CCP test, while for CES test the k/k0<1) and a lower one which is composed by zero-swelling and slippage effects (with the increase of pore pressure the k/k0<1 for both CCP & CES test). For shale samples with well-developed macro-fractures, the apparent permeability theory could not be used to explain the permeability data. Just like coal, the permeability ratio is also bounded by an upper envelope which is corresponding to the solution of free-swelling (with the increase of pore pressure the k/k0>1 for CCP test, while for CES test the k/k0=1) and a lower one which corresponds to zero-swelling (with the increase of pore pressure the k/k0<1 for both CCP & CES test).
Through these comparisons, we found that permeability data for both types of tests are confined within the solutions for two extreme boundary conditions: free-swelling for the upper bound, and zero-swelling and slippage effects combined for the lower bound. These findings suggest that permeability ratios for both CCP tests and CES tests are primarily determined by the matrix-fracture (or pores and dense matrix block) interactions, including sorption-induced swelling/shrinking, through transient effective stresses in matrixes and fractures (or pores and dense matrix block). This non-equilibrium seepage process is very important for shale gas extraction.
Jew, Adam (SLAC National Accelerator Laboratory) | Li, Qingyun (Stanford University) | Cercone, David (National Energy Technology Laboratory) | Brown, Gordon E. (Stanford University) | Bargar, John (SLAC National Accelerator Laboratory)
Barite scale formation in unconventional systems can severely reduce production rates and recovery. Barite in drilling mud (DM) is highly susceptible to dissolution (up to 20% of the total barite) when it interacts with a 15% hydrochloric acid spearhead leading to significant barite scaling as solution pH rises to circumneutral levels. In order to maintain the low pH spearhead that is favored by most operators, a new acid spearhead formulation was developed to stabilize the barite in place, closer to the borehole where open volume is large. This approach is dramatically different than typical scale mitigation practices in which precipitation from solution is targeted for control; but with unsatisfactory results. By using sulfuric acid instead of hydrochloric acid (equivalent acidity), the amount of Ba and SO4 leached from DM was reduced by > 850-fold. This major reduction in barite dissolution translates into a significant reduction in the dispersal of these mineral-forming aqueous species in the hydraulically fractured shale matrix. As a result, reprecipitation of barite scale in the fracture network is minimized. Because some unconventional systems have high concentrations of calcite that dissolves upon interaction with the acid spearhead, gypsum can precipitate due to excess Ca2+ derived from the calcite and its interaction with the additional SO42− introduced from the new acid spearhead formulation. To mitigate this potential scale formation, Na-citrate was added to chelate Ca2+ and inhibit gypsum formation. When only H2SO4 was used, Na-citrate was not able to completely inhibit gypsum formation in high carbonate systems. However, by adjusting the H2SO4/HCl ratios and including Na-citrate, both barite and gypsum scale in the stimulated rock volume can be mitigated. These findings suggest that an incremental new best-practice is to stabilize the Ba/SO4 in place rather than attempt to control precipitation from solution.
Barite is one of the most important and problematic types of mineral scale in unconventional shale systems. Depending on the mineralogy of the deposit and solution pH, the amount and location of barite scale can differ (Figure 1). In systems where the generation of secondary porosity is minimal because of low concentrations of carbonate minerals, the precipitation of barite can reduce permeability by > 15% (Alalli et al., 2018). Efforts to mitigate barite precipitation focus primarily on either keeping barite nucleation from occurring or altering the surface properties of newly formed barite crystals to limit adhesion to shale and pipe surfaces (Antonious, 1996; Jones et al., 2003; Shen et al., 2009; Mavredaki et al., 2011; Yan et al., 2015; Bhandari et al., 2016; He and Vidic, 2016; Yan et al., 2017). These methods have limited success due to the intentional introduction of high quantities of barite in unconventional systems through drilling mud (DM). Previous work has shown that dissolution of barite in DM due to the injection of chemicals into the subsurface, primarily the 15% HCl acid spearhead, releases both Ba2+ and SO42− into the system that can precipitate as barite in fractures and shale matrices (Jew et al., 2018). On a per-mass basis, the barite released from the DM by the acid spearhead is significantly higher than that from the shale itself, indicating that the DM is most likely the dominant Ba/SO4 source in these systems. Because of this underappreciated Ba/SO4 source in unconventional systems, we developed a new model for barite in the subsurface (Figure 2). Because Ba and SO4 are introduced into the system before stimulation fluid injection, any barite dissolved from the DM by the acid spearhead will be transported into stimulated rock volume (SRV) by the slickwater/slurry where precipitation will occur, necessitating a new approach to scale mitigation.
The mechanical properties of kerogen, the organic constituent of shale source rocks, change as it becomes progressively buried under sediment over geologic time. While these changes are due to both mechanical and chemical mechanisms, the individual impact of these mechanisms is poorly understood. In this work, we use atomistic models to isolate how the elastic properties of kerogen are affected by one of these mechanisms: changes in density due to mechanical compaction. We use atomistic models of kerogen at four different maturity levels – immature, top of the oil window, middle-end of the oil window, and over-mature. At each maturity level, we construct representative kerogen structures at densities ranging from 0.9 gm/cm3 to 1.5 gm/cm3 using molecular dynamics simulations. Subsequently, the elastic moduli are calculated at 0 K, 300 K, and 500 K using molecular statics and molecular dynamics simulations.
Kerogen exhibits an amorphous structure with a short-range order up to 6 Å and no discernable long-range order. Increases in kerogen density upon burial are accommodated by proportional increases in the stacking of poly-aromatic islands present in its structure. We show that the increased stacking leads to the formation of π-π stacking bonds, which correlates to the increases in the elastic moduli. We also find that Poisson's ratio measured from atomistic simulations changes linearly with changes in density but is invariant to changes in chemical composition. For all of these properties, the values measured via simulation show good agreement with results from nano-indentation, atomic force microscopy (AFM), and ultrasonic measurements.
These results are useful for several reasons. First, they provide an estimate of Poisson's ratio for kerogen over a range of densities and maturities. This estimate is useful in AFM and nano-indentation experiments, where Poisson's ratio is difficult to measure but is needed to calculate Young's modulus from the reduced modulus. Second, the results demonstrate how atomistic modeling can be applied to gain new insight into the relationship between kerogen structure and its mechanical properties. Third, the agreement between the elastic moduli measured via simulation and experiment shows that atomistic methods can be utilized to accurately characterize kerogen, which is important for building accurate rock models for hydraulic fracturing simulation. Finally, the atomistic models of kerogen developed in this work, constrained by their mechanical properties, can be employed to study other processes such as crack propagation and surface adsorption.
The results of an investigative research study on the impact of the in-situ stress, shale matrix composition, maturity, amount of organic matter and clay composition affecting the anisotropy level of the geomechanical properties have been discussed in this paper. These parameters are among the key factors known to control the geomechanical properties in organic-rich shale formations. Organic-rich shale formations with different mineralogical compositions and organic matter maturity have been measured under uniaxial and triaxial stress state along with the field data from limited number of the wells in these shale basins where the core samples are obtained to investigate the role of each factor on the level of geomechanical anisotropy.
The field data has been analyzed to compare the trends obtained from the laboratory data collected under customized controlled field conditions to the field data trends. Artificial Neural Network (ANN) analysis was used in wells without full log suits to obtain the anisotropic geomechanical parameters. The results highlight the maturation, organic richness and clay composition effect on the recorded field data as well as the geomechanical properties obtained from the laboratory measurements.
The stress and fluid sensitivity of shale formations have been well recognized since the early days of conventional reservoir drilling, completion and production operations as they typically require special attention for minimizing wellbore instability during drilling and maintaining high integrity wells throughout the life cycle of these wells. Shales are highly heterogeneous and anisotropic formations and their source rock characteristics also have introduced further complexities with the organic matter and compositional variations throughout the areal extent of the reservoirs. These variations and their alterations as a function of the level of maturity of the organic matter require further study for better understanding of the differences and similarities between the seal shales and reservoir shales and the role of the organic matter and its maturity level in these differences. One of the critical aspects of the organic matter presence is in quantification of shale mechanical properties and strength and their direction dependence for successful field development. The level of maturity of the organic matter also influences the mechanical, acoustic, petrophysical and failure properties of organic rich shale formations. The mineralogical composition typically deviates from carbonate rich to quartz rich in the rock matrix with clay and organic matter amount and distribution heterogeneity in the reservoir. The layered structure introduced by the depositional history of the formation along with the heterogeneity in the distribution of organic matter result in various degree of anisotropy in reservoir properties (Sondergeld and Rai, 2011; Vernik and Milovac, 2011). A better understanding on the anisotropic characteristics of the shale formations and key parameters impacting the anisotropy is essential for field operational success from exploration studies for seismic attributes to reservoir characterization, drilling and hydraulic fracture design and production optimization.