Inyang, Ubong (Halliburton) | Cortez-Montalvo, Janette (Halliburton) | Dusterhoft, Ron (Halliburton) | Apostolopoulou, Maria (University College London) | Striolo, Alberto (University College London) | Stamatakis, Michail (University College London)
Estimating the effective permeability and microfracture (MF) conductivity for unconventional reservoirs can be challenging; however, a new method for estimating using a stochastic approach is discussed. This new analysis method estimates matrix permeability and the unpropped and propped MF conductivities during laboratory testing where MFs were propped with ultrafine particles (UFPs).
Kinetic Monte Carlo (KMC) simulations form the basis of the method used to estimate effective permeability of the core sample. First, the stochastic model was implemented to calculate effective matrix permeability of a small core taken from unfractured Eagle Ford and Marcellus formation samples using scanning electron microscopy (SEM) images and adsorption data to obtain the pore-size distribution (PSD) within the sample. The KMC approach then evaluated the effect of various parameters influencing the conductivity of laboratory-created MFs. Case studies considered for this work investigate the conductivity improvement of a manmade MF as a function of the UFPs used as proppants that maintain width under high stress, the UFP (proppant) concentration, and the UFP flow perpendicular into a secondary or adjacent MF zone (2ndMF) penetrating the face of an opened MF during flow testing under stress. The leakoff area widths considered were 1, 2, and 3 mm and can be propped or unpropped.
Results obtained for the unfractured Eagle Ford and Marcellus samples closely correlate with other computational and experimental data available. For the laboratory-prepared nonpropped and propped MF samples, the effective propped width was determined to have the greatest effect on the MF conductivity, which increased by two orders of magnitude in the presence of the UFPs. The remaining two factors—proppant concentration and length of 2ndMFs—helped improve the effective MF conductivity in a linear manner; the highest proppant concentration and the 2ndMF zone resulted in the highest fracture conductivity achieved. Insight obtained from this study can be used to optimize fracturing designs by including UFPs and to create strategies for maximizing hydrocarbon recovery during development of unconventional resources where MFs are opened during stimulation treatments.
Shale plays are anisotropic in terms of their reservoir quality which gets reflected in their productivity. Reservoir qualities like organic richness, thermal maturity, hydrocarbon saturation, the volume of clay, brittleness and pressure affect the productivity of the shale plays. In general, the volume of clay has a negative relationship whereas other parameters listed above have a positive relationship with production. In our study area, we found the deepest wells despite having better rock quality; do not perform like nearby shallower wells. The objective of this study is to understand the not so obvious reason behind underperformance of these deepest wells.
Since the wells are located at a deeper depth and the reservoir temperature is high (90 to 135°C), so we studied the area from clay diagenesis and fluid expansion perspective. We have reviewed the imprints of clay diagenesis with the help of XRD data and core integrated multi min processed wireline logs. We observed an increasing trend of illite, chlorite towards the deeper part of the reservoir along with a decreasing trend of smectite in the same direction which indicates a higher degree of clay diagenesis. Fluid expansion study is carried out with the help of total organic carbon and hydrocarbon saturation. This study indicated a higher degree of fluid expansion (TOC to hydrocarbon generation) in the deepest part.
Subsequently, 1D pore pressure, stress and rock mechanical modeling is carried out to evaluate the effect of a higher degree of diagenesis and fluid expansion on geomechanical parameters (pore pressure, stress and brittleness). 1D modeling reveals that the deeper wells have abnormal pressure, stress and low brittleness, which is primarily due to extra pressure contribution from fluid expansion and clay diagenesis apart from the compaction disequilibrium process. This abnormal stress and reduction in brittlness likely to have created challenges for the applied hydrofrac job in the deepest part resulting to narrow frac geometry. Comparison of hydraulic fracture modeling between a shallow and the deepest wells reveal that the hydraulic fracture geometry in the deepest well is narrower than the shallower well. So we came to the conclusion that the deepest wells are underperforming than the shallower wells despite of their better rock quality due to ineffective fracturing and comparatively narrower fracture geometry.
The impact of clay diagenesis and fluid expansion in shale productivity has not been studied widely. Though many authors have extensively studied the impact of clay diagenesis on permeability and pore pressure, the integration of shale well production is rarely attempted. This work will help the operators to better analyze and understand their shale reservoir from clay diagenesis and fluid expansion point of view before planning the hydrofrac jobs.
The booming of shale gas production has affected the natural gas price in the United States (U.S). Natural gas price has plummeted due to the excessive capacity. On the other hand, the import of crude oil and its production of diesel, gasoline, and others are increasing. The problem lies in finding a practical, economical and efficient way of making natural gas marketable. A potential solution is Small-scale Gas-to-Liquids plants. Small-scale GTL can fulfill some of the petroleum products demand such as Gasoline, Ultra-low-sulfur diesel, and jet-fuel. Small-scale GTL plants especially can benefit countries where the gas production is higher than gas demand, yet these countries depend on imported oil.
A Monte Carlo simulation approach is used to conduct sensitivity analysis on various parameters such as the feedstock/natural gas price, plant capacity, plant efficiency, capital expenditure (CAPEX), operational expenditure (OPEX), and products selling prices. The range for natural gas prices and gasoline prices are obtained from average historical data in the United States for the past five (10) years where the shale gas production is booming. The CAPEX is attained from previous GTL project plants before using the Power-Sizing model and literature. The annual OPEX is the percentage fraction of the CAPEX. The plant capacity was chosen based on the diseconomy factor estimated from previous GTL projects. Even with the premium quality of GTL products, the selling price for the products is equal to regular crude oil products.
Economic metrics such as Net Present Value (NPV), Internal Rate of Return (IRR), Cost-to-Profit (C/P) ratio and Payback Period were used to assess the success of GTL technology at each given business case. Results showed that NPV, IRR, C/P ratio and payback period are most affected by CAPEX, products selling price, OPEX, and capacity of the plant, in respected order. Based on these case scenarios and parameters, sensitivity analysis is conducted using Monte Carlo's simulation of 10,000 iterations the results for NPV, IRR, C/P ratio and payback period showed that the GTL project is profitable. The NPVs for the GTL plant in this study are positive for all case scenarios.
It is expected that the outcome of this research would guide shale gas producers and private investors when considering GTL investment to monetize their assets in the United States and beyond.
Wu, Xiaye (The University of Oklahoma) | Han, Lihong (Tubular Goods Research Institute of CNPC) | Yang, Shangyu (Tubular Goods Research Institute of CNPC) | Yin, Fei (Chengdu University of Technology) | Teodoriu, Catalin (The University of Oklahoma) | Wu, Xingru (The University of Oklahoma)
Due to the layered texture and sedimentation environment, shale formations usually characterized as high heterogeneity and anisotropy in in-situ stresses. During the hydraulic fracturing process, fracturing fluid is injected at a pressure above the formation pressure. This injection process changes the local in-situ stresses in a quick and significant manner while generating fracture systems. In the regions of existing geo-features such as natural fractures and faults, local stress changes could lead to the activation of formation movement, which in return impacts the casing going through the locale. Casing deformations during hydraulic fracturing have been observed in Southwest China Sichuan basin, and it have impeded completion operations in certain regions. In order to ensure further exploring, we analyszed this phenomenon and propose practical solutions for fault reactivation prevention.
To study the mechanism of local slippage and the impact on casing integrity, we set up a 2D finite element model with considerations of in-situ stresses acquired from fields, natural fracture orientation from available seismic data, and we simulated water injection process in order to quantify potential slippage and displacement. The finite element model features an integration of casing, cementing, and formation under the hydraulic fracturing conditions. For particular parameters such as permeability and leak-off coefficeint, we conducted sensitivity studies to quantify their impacts on displacement amount.
The theoretical geomechanics studies indicate water induced slippage existence in shale due to its fracture reactivation. Using the finite element model, this paper interpreted and quantified the impact of fracturing fluid injection on casing from strike-slip fault regiems. Simulation results revealed that water injection into natural fractured shale formation can induce finite displacement characterized as fault slippage along discontinues surfaces. This study could help engineers to have a better prediction as how hydraulic fracture intereact with subsurface structures and potential risks that comes along with it. This type of casing damage can be reduced by improving well trajectory design, completion operation, and higher strength level of casing-cement system.
The findings from this study not only can be applied to naturally fractured formations, but also to other pre-existing geo-features such as discountinues surfaces. It also provides fundamental basis for more practical solution to find the measures and overcome the casing deformation problems in hydraulic fracturing.
Ibrahim Mohamed, Mohamed (Colorado School of Mines) | Salah, Mohamed (Khalda Petroleum) | Coskuner, Yakup (Colorado School of Mines) | Ibrahim, Mazher (Apache Corp.) | Pieprzica, Chester (Apache Corp.) | Ozkan, Erdal (Colorado School of Mines)
A fracability model integrating the rock elastic properties, fracture toughness and confining pressure is presented in this paper. Tensile and compressive strength tests are conducted to define the rock-strength. Geomechanical rock properties derived from analysis of full-wave sonic logs and core samples are combined to develop models to verify the brittleness and fracability indices. An improved understanding of the brittleness and fracability indices and reservoir mechanical properties is offered and valuable insight into the optimization of completion and hydraulic fracturing design is provided. The process of screening hydraulic fracturing candidates, selecting desirable hydraulic fracturing intervals, and identifying sweet spots within each prospect reservoir are demonstrated.
Managing adequately pressure drawdown should be a key technical reservoir management driver due to its major impact on cash flow, acceleration and final recovery factor for operating hydraulically fracture shale gas condensate producers. Permeability should be regarded as a key dynamic property for ultra-low permeability shale reservoirs that influences shale hydrocarbon recovery. It is paramount to develop a pressure depletion plan that captures the pressure drawdown strategy and the changes in flow capacity associated to the interaction of the nano-Darcy rock and hydraulic fractures with stress dependent permeability effects.
Defining the adequate drawdown strategy would aid maximizing the economic recovery. Considering the variability of permeability with pressure drawdown should be part of the reservoir management lifecycle for unconventional shale reservoirs. This study focus on evaluating the impact of pressure drawdown strategy on initial rates and recovery for a Duvernay Gas condensate producer with an initial condensate yield of 100-150 stb/mmscf.
A sector compositional reservoir simulation model was built for a horizontal multistage hydraulically fracture Duvernay shale gas condensate producer. A full assessment of variability of permeability in the nano-Darcy rock and in the propped hydraulic fracture stages near the wellbore region was accomplished. Aggressive, moderate and conservative pressure drawdown strategies were evaluated, considering multiple operational pressure drawdown incremental ranges from 14.5 to 95 psia per day.
Results clearly indicate that implementing daily pressure drawdown increments of 22 to 29 psia per day would provide a similar recovery factor than imposing daily pressure drawdowns of 44 to 95 psia per day. However, there is a golden operating window opportunity to accelerate recovery by imposing maximum drawdown from the early days of production and bringing significant benefits of accelerating recovery with an associate increase in revenue but the benefits of this acceleration vanished in less than one year due to substantial changes in hydraulic fracture conductivity and also in the nano-Darcy rock permeability in the near wellbore region. The reduction of nano-Darcy permeability is a function of pressure, time and distance from the hydraulic fractures. According to our results, the best reservoir management practice for operating lean/medium Gas Condensate unconventional shale producers should be maximizing pressure drawdown at the early stage of the life cycle and deferring the installation of production string to maximize inflow-outflow.
This study analyzes the production data from 2,755 horizontal wells in the Haynesville shale. Correlations were generated to predict 4,5,6, and 7-year cumulative productions from initial 6,12 and 24-months production data. These correlations can help in field development planning and economic analysis. The residuals (Predicted – Actual Cumulative Production) from these correlations were also analyzed and this technique can be used to identify wells affected by interference, refracturing, frac-hits, etc.
The cumulative production estimates from the developed correlations were also compared with the corresponding estimates from the DCA equations (seven different DCA methods used). The accuracy of prediction based on correlations developed in this study is at par with the various standard DCA methods published and used in the industry. The correlations are much faster to use and easier to implement for a large number of wells.
Another objective of the paper was to develop P10, P50 and P90 type curves for the Haynesville shale using the available production data. A subset of the total wells i.e. 150 wells evenly distributed throughout the study area, were used for predicting type curves. These type curves were generated and compared using different Decline Curve Analysis (DCA) models. The different DCA methods predicted an uncertainty of 5 to 27 % for the P10, P50 and P90 production profiles.
Operators in unconventional shales are continuously looking for ways to reduce potential emissions from production facilities. This is especially challenging in liquid-rich regions, such as the Marcellus Shale. As regulations and various industry best practices evolve, facility designs and equipment must evolve as well. Facility-design improvements and successful operational procedures were examined to eliminate or significantly reduce emissions (Porter et al. 2016).
By taking a proactive approach, operators can significantly reduce emissions. In a previous work (Porter et al. 2016), we discussed the key elements of a successful program: (1) a facility design and operational philosophy that considers emission controls, (2) a comprehensive maintenance program that addresses all unplanned or unintended releases encountered during optical-gas-imaging inspections and allows for feedback to facilitate corrective action, and (3) a focused plan for improving technology to diminish the quantity of future leaks. Applying enhanced technology and past experiences to older designs is often the most efficient measure for reducing potential emissions. While these elements are crucial, equally important is the historical defining and tracking of actual identified leaks and the documentation of corrective actions that were taken (Porter et al. 2016). This work further corroborates these key elements.
Additional facility designs for maximum emissions reduction were compared to facility designs in our previous work (Porter et al. 2016), using calculated emissions for each scenario. As well production increases (owing to longer lateral drilling and enhanced stimulation practices), wellsite liquid handling and vapor control become challenging. Techniques for effectively controlling vapors and mitigating emissions were explored in detail, using an actual case study. Also, a previous leak-detection field study with preliminary data was updated with additional years of data, which yielded further clarification of emissions released on a field and pad level with resulting variations in time. Detailed data analysis compiled from inspections identified the most common areas where leaks occur within a production facility—the majority of which were located on atmospheric stock tanks. Data further demonstrated the effectiveness of higher-quality tank relief valves for reducing fugitive leaks.
Production-facility emissions can be managed by using effective production-facility designs and technologies. The present work offers an improved understanding of how technological evolutions can support effective design solutions and processes in a modern shale-gas development (Porter et al. 2016).
Seunghwan Baek and I. Yucel Akkutlu, Texas A&M University Summary Source rocks, such as organic-rich shale, consist of a multiscale pore structure that includes pores with sizes down to the nanoscale, contributing to the storage of hydrocarbons. In this study, we observed hydrocarbons in the source rock partition into fluids with significantly varying physical properties across the nanopore-size distribution of the organic matter. This partitioning is a consequence of the multicomponent hydrocarbon mixture stored in the nanopores, exhibiting a significant compositional variation by pore size-- the smaller the pore size, the heavier and more viscous the hydrocarbon mixture becomes. The concept of composition redistribution of the produced fluids uses an equilibrium molecular simulation that considers organic matter to be a graphite membrane in contact with a microcrack that holds bulk-phase produced fluid. A new equation of state (EOS) was proposed to predict the density of the redistributed fluid mixtures in nanopores under the initial reservoir conditions. A new volumetric method was presented to ensure the density variability across the measured pore-size distribution to improve the accuracy of predicting hydrocarbons in place. The approach allowed us to account for the bulk hydrocarbon fluids and the fluids under confinement. Multicomponent fluids with redistributed compositions are capillary condensed in nanopores at the lower end of the pore-size distribution of the matrix ( 10 nm). The nanoconfinement effects are responsible for the condensation. During production and pressure depletion, the remaining hydrocarbons become progressively heavier. Hence, hydrocarbon vaporization and desorption develop at extremely low pressures. Consequently, hydrocarbon recovery from these small pores is characteristically low. Introduction Resource shale and other source-rock formations with significant amounts of organic matter, such as mudstone, siltstone, and carbonate, have a multiscale pore structure that includes fractures, microcracks, and pores down to a few nanometers (Ambrose et al. 2012; Loucks et al. 2012). The total amount of hydrocarbons stored is directly proportional to the amount of organic matter.
Significant research has been conducted on hydrocarbon fluids in the organic materials of source rocks, such as kerogen and bitumen. However, these studies were limited in scope to simple fluids confined in nanopores, while ignoring the multicomponent effects. Recent studies using hydrocarbon mixtures revealed that compositional variation caused by selective adsorption and nanoconfinement significantly alters the phase equilibrium properties of fluids. One important consequence of this behavior is capillary condensation and the trapping of hydrocarbons in organic nanopores. Pressure depletion produces lighter components, which make up a small fraction of the in-situ fluid. Equilibrium molecular simulation of hydrocarbon mixtures was carried out to show the impact of CO2 injection on the hydrocarbon recovery from organic nanopores. CO2 molecules introduced into the nanopore led to an exchange of molecules and a shift in the phase equilibrium properties of the confined fluid. This exchange had a stripping effect and, in turn, enhanced the hydrocarbon recovery. The CO2 injection, however, was not as effective for heavy hydrocarbons as it was for light components in the mixture. The large molecules left behind after the CO2 injection made up the majority of the residual (trapped) hydrocarbon amount. High injection pressure led to a significant increase in recovery from the organic nanopores, but was not critical for the recovery of the bulk fluid in large pores. Diffusing CO2 into the nanopores and the consequential exchange of molecules were the primary drivers that promoted the recovery, whereas pressure depletion was not effective on the recovery. The results for N2 injection were also recorded for comparison.