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US unconventional resource production has developed tremendously in the past decade. Currently, the unconventional operators are trying many strategies such as refracturing, infill drillings and well spacing optimization to improve recovery factor of primary production. They are also employing big data and machine learning to explore the existed production data and geology information to screen the sweet spot from geology point of view. However, current recovery factor of most unconventional reservoirs is still very low (4~10%). A quick production rate decline pushes US operator to pursue gas EOR for unconventional reservoirs, lifting the ultimate recovery factor to another higher level. The goal of this work is to improve oil recovery by implementing gas Huff and Puff process and optimizing injection pattern for one of the US major tight oil reservoirs - Eagle Ford basin. Gas diffusion is regarded as critical for gas Huff and Puff process of tight oil reservoirs. Utilizing the dual permeability model, gas diffusion effect is systematically analyzed and compared with the widely used single porosity model to justify its importance. Transport in natural fractures is proved to be dominated recovery mechanism using dual permeability model. Uncertainty studies about reservoir heterogeneity and nature fracture permeability are performed to understand their influences on well productivity and gas EOR effectiveness. Moreover, three alternative gas injectant compositions including rich gas, lean gas and nitrogen are investigated in gas Huff and Puff processes for Eagle Ford tight oil fractured reservoir. The brief economic evaluation of Huff and Puff project is conducted for black oil region of the Eagle Ford basin.
Engineers commonly expect symmetric fracture wings in multiple transverse fracture horizontal wells (MTFHWs). Microseismic surveys have shown asymmetric hydraulic fracture grow away from the recent fractured wells and grow towards previous produced wells. It might be caused by the elevated stress around the recently fractured well and the reduced stress near the depleted wells. This paper presents the asymmetric fracture growth observed by the microseismic events and develops a simple model to simulate the fracture propagation and its impact on the well productivity. Motivated by the microseismic observations, we developed a simple fracture model to simulate asymmetric fracture wings that can capture the behavior of fracture hits between two adjacent horizontal fractured wells. Also, we developed a model to estimate the productivity of a well with asymmetric fractures. The newly developed fracture model shows that the fracture can grow asymmetrically if the horizontal well is located where stress field is different between its two sides.
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.
One of the considerations in hydraulic fracturing treatment optimization in unconventional (shale/tight/CBM) reservoirs is creating fracture complexity through reducing or possibly eliminating or neutralizing the in-situ stress anisotropy (differential stress) to enhance hydraulic fracture conductivity and connectivity by activating planes of weakness (natural fractures, fissures, faults, cleats, etc.) within the formation in order to create secondary or branch fractures (induced stress-relief fractures) and connect them to the main bi-wing hydraulic fractures. However, actual field experience has shown that some reservoirs under certain treatment designs exhibit excessive fracture complexity due to excessive induced stresses or stress shadowing that can result in pressureout or screenout, and thus, poor well completion and productivity performance. Therefore, it is crucial to identify the reservoir candidates and treatment strategies that are suitable for enhancing fracture complexity to avoid fracturing treatment scenarios that will have an adverse effect on the well productivity.
In this work, a three-dimensional hydraulic fracture extension simulator is coupled with a reservoir production simulator to screen for the reservoir candidates and fracturing treatment scenarios that can lead to enhancing fracture complexity, conductivity, and connectivity and positive well production performance. Furthermore, scenarios are identified under which excessive fracture complexity (due to excessive induced stresses or stress shadowing) results in poor well completion performance.
The results indicate that fracture complexity can be enhanced under the following treatment scenarios: (1) low-viscosity slickwater with smaller proppant sizes under high treatment rates, (2) hybrid fracture treatment (low-viscosity slickwater containing smaller proppants and low proppant concentrations with high treatment rates followed by viscous treatment fluids containing larger proppants and higher proppant concentrations), (3) simultaneous fracturing of multiple intervals at close spacing, and, (4) out-of-sequence pinpoint fracturing (fracturing Stage 1 and then Stage 3 followed by placing Stage 2 between the previously fractured Stages 1 and 3). It is also revealed that the success of each of the above treatment scenarios is very sensitive to rock brittleness (combination of Young's modulus and Poisson's ratio), magnitude of stress anisotropy, matrix permeability, process zone stress/net extension pressure, fracture gradients, and treatment fluid viscosity and rate. Additionally, excessive fracture complexity, which impedes fracture growth due to pressure out and screenout, can be mitigated by reducing treatment rate and pressure, increasing treatment fluid viscosity, and using small particulates, such as 100-mesh proppant.
This work is the first attempt in comparative evaluation of the impact of creating fracture complexity under a variety of operationally-feasible treatment scenarios applied to a wide range of reservoir and rock geomechanical properties. It shows that wells with certain combinations of Young's modulus, Poisson's ratio, stress anisotropy, and fracture gradients are not suitable candidates for creating complexity in the hydraulic fractures system.
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.
The key factor for characterizing unconventional shale reservoirs is the total organic carbon (TOC). TOC is estimated conventionally by analysis cores samples which requires extensive lab work, thus it is time-consuming and costly. Several empirical models are suggested to estimate the TOC indirectly using conventional well logs. These models assume the TOC and well logs are linearly related, this assumption significantly reduces the TOC estimation accuracy. In this work, the design parameters of the artificial neural network (ANN) were optimized using selfadaptive differential evolution (SaDE) method to effectively predict the TOC from the conventional well log data. A new correlation for TOC calculation was developed, which is based on the optimized SaDE-ANN model.
This course covers the fundamental principles concerning how hydraulic fracturing treatments can be used to stimulate oil and gas wells. It includes discussions on how to select wells for stimulation, what controls fracture propagation, fracture width, etc., how to develop data sets, and how to calculate fracture dimensions. The course also covers information concerning fracturing fluids, propping agents, and how to design and pump successful fracturing treatments. Rock mechanics/in-situ stress aspects of fracturing Reservoir aspects of fracturing (How much fracture do I need?) Fracture mechanics Fracture design variables Perforating for fracturing Fracture diagnostics
Operators and service providers commonly experience problems with DFIT execution and analysis despite efforts to reduce errors and inconsistencies. Before any field execution or analysis, the objectives of a DFIT must be considered. Historically, DFITs were performed predominantly for the purpose of designing better full-scale hydraulic-fracture treatments with early-time measurements of initial shut-in pressure, leakoff coefficient, and fracture closure having priority over reservoir parameters such as permeability and pore pressure. Increasingly, practitioners are using DFITs to measure reservoir parameters such as initial pressure and permeability. While, in many cases, these parameters may be obtained from a single successful test, other situations have time constraints or rock and reservoir properties that constrain operations to a point where priorities must be set. While leakoff and closure values are determined early in the DFIT shut-in period, reservoir pressure and permeability are derived from late-time measurements that may require longer falloff times. The complete paper presents cases encountered in which test procedures/operations or incorrect analysis misled engineers.