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Liu, Kui (State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development) | Dahi Taleghani, Arash (Sinopec Research Institute of Petroleum Engineering) | Gao, Deli (China University of Petroleum, Beijing)
Summary Casing failure in shale gas wells has seriously impacted production from Weiyuan and Changning fields in Sichuan Province, China. Apparently, interaction of hydraulic fractures with nearby faults causes fault slippage, which in some situations has led to well shearing. Hence, we propose a semianalytical model in this paper to estimate the length of slippage along the fault that is caused by pressurization of a fault intercepted by the hydraulic fracture. These calculations have been performed for different configurations of the fault with respect to the hydraulic fracture and principal stresses. Using the semianalytical model provided in this paper, two fault slippage cases are calculated to assess the casing failure in nearby wells. In one case study, the calculated results of the fault slippage are consistent with the scale of casing deformation in that well and a microseismic magnitude caused by fault slippage is calculated that is larger than the detected events. The presented model will provide a tool for a quick estimation of the magnitude of fault slippage upon intersection with a hydraulic fracture, to avoid potential casing failures and obtain a more reliable spacing selection in the wells intersecting faults. Introduction The shale gas revolution has increased natural-gas supply in the United States and is about to change the world energy map very soon. New technology developments in horizontal drilling and multistage hydraulic fracturing have played critical roles in this revolution. Hydraulic-fracturing treatments mostly take place in multiple stages as thousands of cubic meters of fracturing fluid are injected into the formation in each stage over the course of a few hours. However, a few incidents of fault reactivation as a result of hydraulic fracturing has attracted some attention recently (Wasantha and Konietzky 2016). Before the research on the fault slippage caused by hydraulic fracturing in the shale plays, many earthquakes caused by fluid injection were reported in the literature. The first well-documented earthquake, identified to be caused by fluid injection, occurred in 1960.
Surfactant floods can attain high oil recovery if optimal conditions with ultralow interfacial tensions (IFT) are achieved in the reservoir. A recently developed equation-of-state (EoS) phase-behavior net-average-curvature (NAC) model based on the hydrophilic-lipophilic difference (HLD-NAC) has been shown to fit and predict phase-behavior data continuously throughout the Winsor I, II, III, and IV regions. The state-of-the-art for viscosity estimation, however, uses empirical nonpredictive based on of fits to salinity scans, even though other parameters change, such as the phase number and compositions. In this paper, we develop the first-of-its-kind microemulsion viscosity model that gives continuous viscosity estimates in composition space. This model is coupled to our existing HLD-NAC phase-behavior EoS.
The results show that experimentally measured viscosities in all Winsor regions (two- and three-phase) are a function of phase composition, temperature, pressure, salinity, and the equivalent alkane carbon number (EACN). More specifically, microemulsion viscosities associated with the three-phase invariant point have an M shape as formulation variables change, such as from a salinity scan. The location and magnitude of viscosity peaks in the M are predicted from two percolation thresholds after tuning to viscosity data. These percolation thresholds as well as other model parameters change linearly with EACN and brine salinity. We also show that the minimum viscosity in the M shape correlates linearly with EACN or the viscosity ratio. Other key parameters in the model are also shown to linearly correlate with the EACN and brine salinity. On the basis of these correlations, two- and three-phase microemulsion viscosities are determined in five-component space (surfactant, two brine components, and two oil components) independent of flash calculations. Phase compositions from the EoS flash calculations are entered into the viscosity model. Fits to experimental data are excellent, as well as viscosity predictions for salinity scans not used in the fitting process.
We propose a new semianalytical method for analyzing flowback water and gas production data to estimate hydraulic fracture (HF) properties and to quantify HF dynamics. The method includes a semianalytical flowback model, a set of two-phase diagnostic plots, and a workflow to evaluate initial fracture volume and permeability, as well as fracture compressibility and permeability modulus. The flowback model incorporates two-phase water and gas flow in both HF and matrix domains and considers variations of fluid and rock properties with pressure. The HF domain is modeled by boundary-dominated flow, whereas an infinite-acting linear flow is assumed for the matrix domain. The flowback model is developed by assigning the variable average pressure in the fracture as the inner boundary condition for matrix according to Duhamel’s principle. The average pressure in the fracture and distance of investigation (DOI) in the matrix are calculated from a modified material-balance equation by updating the matrix DOI as well as phase saturation and relative permeability in both the fracture and matrix domains. A modified DOI equation is used for two-phase flow in the matrix, which considers the pressure-dependent fluid and rock properties in pseudotime. The diagnostic plots shed light on the identification of flow regimes during the coupled two-phase flow in both fracture and matrix. The proposed workflow quantifies the HF dynamics through the loss of both fracture volume and fracture permeability by reconciling flowback and long-term production data. The accuracy of the new method is tested against numerical simulations conducted by a commercial numerical simulator. The validation results confirm that the proposed method accurately predicts initial fracture volume, permeability, and permeability modulus. Further, we use production data from a multifractured horizontal well (MFHW) drilled in Marcellus Shale to test the practicality of the proposed method. The results show a significant reduction in fracture volume and permeability during production attributable to the HF closure.
Considerable research has been focused on the development of rate-transient-analysis (RTA) models to estimate the reserves of gas/condensate reservoirs. Currently, broadly deployed RTA tools rely on multiphase pseudopressure concepts to enable multiphase production-data analysis. In any multiphase pseudopressure calculation, the determination of the saturation/pressure (So/p) relationship plays a vital role because it directly influences the ability of multiphase RTA methods to reliably forecast original gas in place (OGIP). In this work, we present a thermodynamics-based So/p model that provides a better understanding of the phase behavior for the boundary-dominated gas/condensate reservoirs. The proposed So/p model is derived from the thermodynamic nature of extended black-oil formulations. A noniterative flash-calculation protocol is used to establish the So/p path in the condensate-buildup region. The developed method can be coupled with RTA tools and services for the calculation of multiphase pseudopressure. In this work, we present case studies of three gas/condensate reservoirs with different types of fluids. Two RTA multiphase analysis models are used to scrutinize the production data using the newly proposed So/p relationship, and results are compared with the use of a traditional steady-state method coupled with constant-volume-depletion (CVD) data. Results of the case studies show that RTA models that use the proposed So/p consistently yield more accurate OGIP estimation. Thus, this work presents a practical approach to remove commonly used yet potentially faulty assumptions in multiphase RTA applications for liquid-rich gas/condensate reservoirs.
We present a new semianalytical compositional model designed for primary production of multicomponent oil and cyclic solvent injection in ultratight oil reservoirs that is dependent on diffusion-dominated transport within the matrix (k<200 nd) coupled to advection-dominated transport in the fractures. The semianalytical model consists of a well-mixed tank model for the fractures coupled to diffusive transport within the matrix. Production of oil, gas, and water from the fractures to the well is proportional to its phase mobility. The matrix allows for differing effective-diffusion coefficients for each component. Because there are no gridblocks within the matrix, the analytical solution is computationally less expensive than numerical simulation while capturing the steep, nonmonotonic compositional changes occurring a short distance into the matrix that result from multiple injection cycles. The Peng-Robinson equation of state (PR EOS) (Robinson and Peng 1978) is used to calculate phase behavior with time within the fractures and to initialize density and mass concentrations within the matrix based on the semianalytical framework.
The coupled convective (fracture) and diffusive (matrix) model is validated with several laboratory- and field-scale cases. For primary recovery, the results show that the model correctly reproduces the pressure and oil-recovery declines observed in the field. We show that the hydrocarbon-recovery mechanism for solvent huff ’n’ puff (HnP) is facilitated by greater density reduction and compositional changes. Two solvents are considered in HnP calculations: carbon dioxide (CO2) and methane (CH4). Recovery of heavier components is enhanced with CO2 compared with CH4 within the reservoir (matrix and fractures). Furthermore, the results demonstrate that multiple HnP cycles constrained to surface injection are needed to enhance density and compositional gradients, and therefore oil recovery. Although shorter soaks are better for short-term recovery (i.e., 3 to 5 years), longer soaks maximize recovery over a longer time frame (i.e., 10 to 15 years). This paper provides a limiting case model based on diffusive matrix transport and convective fracture transport to determine the optimal number/duration of cycles and when to start the HnP process after primary recovery.
Reservoir depletion may induce substantial changes in the stress state of the subsurface rock. The interaction between the pore fluid pressure and rock stress alters the reservoir rock porosity and permeability which, in turn, can reversely affect the productivity index (PI) of producing wells.
A nonlinear analytical solution is developed for the drawdown-dependent PI of reservoirs under a steady-state flow regime. Biot’s theory of poroelasticity is used to derive the depletion-induced changes in the reservoir rock porosity and permeability. The well-known Mindlin’s solution for a nucleus of strain in a semi-infinite elastic medium is adopted as Green’s function and integrated over the depleted volume of a disk-shaped reservoir to obtain the 3D distribution of rock stress and volumetric strain. The fluid transport equation is nonlinearly related to the solid mechanics side of the problem via the stress-dependent permeability coefficients. A perturbation technique is used to mathematically treat the described nonlinearity and analytically solve the equations of pore fluid flow and rock stress under steady-state flow regime. A good match is captured between the obtained analytical perturbation solution and the numerical finite difference solution of the same problem.
Results confirm the expected strong dependence of the Well PI on the drawdown magnitude. The poroelastic constitutive parameters of the reservoir rock determine the extent of such dependency. The rock initial porosity has the strongest influence on the Well PI, followed by the reservoir initial permeability and solid grain modulus, while the reservoir depth to radius ratio and the Poisson’s ratio are found to be the least sensitive parameters.
Zhang, Kaiyi (Virginia Polytechnic Institute and State University) | Nojabaei, Bahareh (Virginia Polytechnic Institute and State University) | Ahmadi, Kaveh (Pometis Technology) | Johns, Russell T. (Pennsylvania State University)
Shale and tight reservoir rocks have pore throats on the order of nanometers, and, subsequently, a large capillary pressure. When the permeability is ultralow (k < 200 nd), as in many shale reservoirs, diffusion might dominate over advection, so that the gas injection might no longer be controlled by the multicontact minimum miscibility pressure (MMP). For gasfloods in tight reservoirs, where k > 200 nd and capillary pressure is still large, however, advection likely dominates over diffusive transport, so that the MMP once again becomes important. This paper focuses on the latter case to demonstrate that the capillary pressure, which has an impact on the fluid pressure/volume/temperature (PVT) behavior, can also alter the MMP.
The results show that the calculation of the MMP for reservoirs with nanopores is affected by the gas/oil capillary pressure, owing to alteration of the key tie lines in the displacement; however, the change in the MMP is not significant. The MMP is calculated using three methods: the method of characteristics (MOC); multiple mixing cells; and slimtube simulations. The MOC method relies on solving hyperbolic equations, so the gas/oil capillary pressure is assumed to be constant along all tie lines (saturation variations are not accounted for). Thus, the MOC method is not accurate away from the MMP but becomes accurate as the MMP is approached when one of the key tie lines first intersects a critical point (where the capillary pressure then becomes zero, making saturation variations immaterial there). Even though the capillary pressure is zero for this key tie line, its phase compositions (and, hence, the MMP) are impacted by the alteration of all other key tie lines in the composition space by the gas/oil capillary pressure. The reason for the change in the MMP is illustrated graphically for quaternary systems, in which the MMP values from the three methods agree well. The 1D simulations (typically slimtube simulations) show an agreement with these calculations as well. We also demonstrate the impact of capillary pressure on CO2-MMP for real reservoir fluids. The effect of large gas/oil capillary pressure on the characteristics of immiscible displacements, which occur at pressures well below the MMP, is discussed.
Summary One of the critical issues that occur in many oil and gas wells is the failure of the cement sheath because of debonding from the casing string or from the formation. This results in the formation of microannuli, which can become pathways for fluid migration. Cement shrinkage during setting is regarded as one of the main causes of the formation of microannuli. In this paper, a new class of polymerbased expandable additives in the form of fibers is incorporated into the cement to compensate for shrinkage and thereby help prevent the formation of microannuli in oil and gas wells. The proposed fiber additives are made from shape-memory polymers (SMPs) and expand when exposed to temperatures above a specific value that is, by design, below the downhole temperature of the cemented zone. As a result of the expansion of the cement paste, flow channels and fluid migration may significantly decrease while preserving the mechanical properties required for the mechanical integrity of the cement sheath. The bridging effect of fibers across individual microcracks helps control the propagation and coalescence of small fractures. Considering the inert property of the proposed additive, the water-cement ratio and its chemical properties do not need to be revisited. The measured increase in cement ductility makes the cement system more resistant to cracking. The cement expansion, fluid loss, gel strength, compressive strength, ductility, and tensile strength of the samples containing these fibers are examined using destructive and nondestructive methods, as reported here. The proposed class of expandable additives can help operators reach sustainable well integrity by increasing the contact stress at the cement-casing and the cement-formation interfaces to prevent fluid migration and the propagation of cracks. Introduction Unwanted fluid migration in the annulus can severely compromise wellbore integrity, affecting not only long-term production but also the injection efficiency of the well. Annular gas flow outside the casing is usually associated with failure of the cement sheath.
We propose a novel cement additive made of graphite nanoplatelets (GNPs) for improved hydraulic isolation and durability of oil and gas wells. The primary role of the cement sheath, which is zonal isolation, can be significantly affected by the permeability of set cement (hardened cement slurry). On one hand, it is the inherent microstructural defects of cement, including pores and microcracks, that results in the intrinsic permeability of cement, and on the other hand, cracking, micro-annuli, or other flow paths developed through the disturbed cement by connecting the pre-existing microstructural defects determine the equivalent permeability of set cement. The purpose of this research is containing or at least minimizing the intrinsic and developed flow paths through the cementitious matrix with the help of surface-modified GNPs. GNPs possess high surface area to volume ratios. In this study, we focus on the effect of surface-modified GNPs on the overall mechanical properties of both cement slurry and hardened cement slurry affecting the permeability of cement. We present two dispersion methods on the basis of physical and chemical treatments of the surface properties of GNPs. The efficiency of proposed methods on the overall properties of the cement is examined before and after its setting. To mimic downhole conditions, cement slurries are cured at 3,000 psi and 190°F for 24 hours. Also, some experiments were repeated under the pressure and temperature conditions up to 5,160 psi and 126°F, respectively, to examine pumpability and behavior of cement slurry at bottomhole conditions. To examine the role of spatial distribution of GNPs on the hardened cement nanocomposite, samples with different concentrations of GNPs were tested. We investigated the effect of modified GNPs on the unconfined compressive strength (UCS), shear bond strength, thickening time, rheological characteristics, and the free fluid content. We measured zero free fluid at room temperature for different concentrations of GNPs, demonstrating uniform dispersion of nanoparticles within the cement matrix. On the other hand, the squeeze of water out of the lower parts of the cement slurry and its upward migration can develop preferential paths for oil and gas migration. Therefore, eliminating the above-mentioned water separation can enhance cement sealing properties. We found that an optimum 0.2 vol% concentration of acid-functionalized GNPs improves the compressive and the shear bond strength of the prepared cement by approximately 42 and 175% as compared to the plain cement, respectively.
Summary Current rate-transient-analysis tools for gas wells producing under boundary-dominated-flow (BDF) conditions largely rely on the deployment of the Arps empirical decline models (Arps 1945), or liquid-based analytical models rewritten in terms of pseudofunctions. Recently, Stumpf and Ayala (2016) demonstrated that, contrary to common practice, decline exponents (b) used in Arps' hyperbolic equations when applied to gas-well analysis can be rigorously estimated before any field-production data are collected. This determination is solely dependent on gas pressure/volume/temperature (PVT) properties and prevailing constant-bottomhole-pressure (BHP) specification for volumetric, single-phase gas-flow conditions. In the study, we extend that work to a more-realistic variable-BHP condition, which is the most common production-specification condition, in terms of the ratio of changing BHP to average reservoir pressure. The decline exponent (b) is thus rederived, and it is shown that under such conditions, variable BHP hyperbolic decline coefficients become solely dependent on fluid PVT properties and take their largest possible magnitude compared with constant-BHP production. Step-by-step analysis procedures are presented that enable explicit and straightforward estimation of original gas in place (OGIP) and other reservoir properties by universal-type-curve and straight-line analysis. Finally, several cases using simulated and field data are discussed in detail to validate the capabilities of the proposed approach. Introduction Rate and pressure are the most valuable data in reservoir-engineering analysis. Either directly or indirectly, they are inputs needed in all phases of reservoir-performance calculations.