Rivero, Jose A. (Schlumberger Canada) | Faskhoodi, Majid (Schlumberger Canada) | Ferrer, Giselle Garcia (Schlumberger Canada) | Mukisa, Herman (Schlumberger Canada) | Zhmodik, Alexey (Schlumberger Canada)
In unconventional reservoirs that rely on hydraulic fractures for production, displacement Enhanced Oil Recovery (EOR) methods are difficult to apply due to the low matrix permeabilities that impede the flow of the injected agents through the formation. This leaves cyclic methods, also known as huff-and-puff as one of the possible alternatives for improving recovery in these types of reservoirs.
Since 2014, a considerable amount of literature and research has been devoted to the feasibility, implementation and optimization of gas Huff-and-Puff in fractured unconventionals. Most of these studies have been devoted to oil reservoirs and few publications have addresses gas condensates.
In this study, we investigate the feasibility of using lean hydrocarbon gas mixtures to increase recovery in a typical gas condensate reservoir in the Montney formation. To perform this study, we used publicly available data to build a representative Montney gas condensate reservoir. A finite-element hydraulic fracture simulator was employed to create a series of hydraulic fracture geometries that were later modeled with a compositional reservoir simulator to forecast primary production and liquid recovery under different Huff-and-Puff scenarios. We conducted sensitivity studies to test the effect of the injected gas composition and soaking time. Additionally, the impact of fracture geometries (complex vs. planar) was also investigated.
We found that soaking time had a measurable effect on liquid recovery as it allows the pressures between the fractures and matrix to equilibrate, thereby affecting the volume of condensate that can revaporize. The choice of solvent has a strong effect on the amount of condensate uplift, with leaner gasses recovering less. Finally, higher incremental liquids production with Huff-and-Puff was strongly correlated with higher pressures since they allowed for more re-vaporization. Fracture geometries were found to have considerable influence on the pressure profiles during the production and injection periods; therefore, the degree of complexity of the fracture played a role in the performance of the EOR process.
Oil production from shale reservoirs has increased dramatically in the recent years. To identify drilling targets and optimize well completions, it is important to get early access to reservoir fluid properties. However, due to the low permeability of shale reservoirs, fluid samples often become available only after most important development decisions have been made. Therefore, it has been an abiding challenge in the industry how to acquire fluid properties data earlier in shale reservoirs.
Mud logging gas data acquired while drilling provide the earliest hydrocarbon response from the reservoir. In an earlier study, we have demonstrated that advanced mud gas data have large potential to predict reservoir fluid properties. In general, fluid properties are strongly correlated with thermal maturity of the source rock. In shale reservoirs, reservoir fluids are still in the source rock, as low permeability limits migration and convection of the reservoir fluids. As a result, the reservoir fluid systems in shale reservoirs are relatively undisturbed and have a high degree of consistency. This provides the possibility to correlate advanced mud logging gas data and reservoir fluid properties.
Based on a reservoir fluid database with more than 60 samples from different shale reservoirs, we developed a machine learning algorithm to predict fluid properties from advanced mud logging gas data. The accuracy of the new method is significantly improved compared with the previous model which used an explicit correlation based on wetness. In addition, the new approach is more general and does not depend on a specific shale reservoir. We applied the new model to 11 wells with advanced mud logging gas data. The predicted gas oil ratios are close to the measurement from early production data when advanced mud logging gas data are of good quality.
This publication demonstrates that advanced mud logging gas data can be used to acquire reservoir fluid properties in shale reservoirs. Such approach provides a novel and cost-efficient solution for the sampling challenges in early phase. In addition, the method provides continuous fluid data along entire well, as opposed to a single fluid sample taken at a specific location. Hence the results provide insight in the fluid distribution in shale reservoirs. The method can be widely used for sweet spot identification and optimizing fracking strategy in shale reservoirs.
Fu, Qinwen (University of Kansas) | Cudjoe, Sherifa (University of Kansas) | Barati, Reza (University of Kansas) | Tsau, Jyun-Syung (University of Kansas) | Li, Xiaoli (University of Kansas) | Peltier, Karen (University of Kansas - Tertiary Oil Recovery Project (TORP)) | Mohrbacher, David (Chesapeake Energy) | Baldwin, Amanda (Chesapeake Energy) | Nicoud, Brian (Chesapeake Energy) | Bradford, Kyle (Chesapeake Energy)
Fracture complexity, phase behavior, lithological variations and diffusion of gas from the fracture into the oil-saturated nano-pores are the main contributing factors in oil recovery using gas huff-n-puff injection. Limited research was conducted to define diffusion coefficients coupled with the rock tortuosity. The objective of this work is to conduct a comprehensive experimental and simulation study on Lower Eagle Ford rock samples to measure the diffusion coefficients for different injection cycles in three representative litho-facies.
Three representative rock samples were selected based on their differences in petrophysical properties. Saturated volumes were measured using a low-field nuclear magnetic resonance (NMR) measurement and confirmed with material balance for cores saturated at reservoir conditions. Pressure was recorded during a one-day diffusion process before it was dropped linearly at the end of each cycle for production, and the effluent oil and gas composition were measured. NMR measurement was repeated at the end. A compositional simulation model was set up using tortuosity values from FIB-SEM analysis to simulate the experimental diffusion and production. History matching on pressure and production results was conducted and diffusion coefficients were estimated for one representative sample.
Pressure profiles vary significantly between different cycles due to different effective diffusion coefficients. This may be caused by invasion of the gaseous phase into a new section of the pore network during each cycle. Diffusion coefficients, represented by pressure drop during the soaking time, vary across different litho-facies and for different cycles. For the produced oil, the concentration of lighter oil components declined from the first to the last cycle of gas injection while the concentration of the intermediate and heavier components increased.
Gas huff-n-puff injection into shale oil reservoirs is being investigated from the point of view of diffusion and variations in rock properties for the first time and measurements were validated using numerical simulation. The huff-n-puff experiments show favorable results, using constant volume diffusion cell with locally produced hydrocarbon gas and stock-tank oil, the recovery factors for samples A, B, and C are 57.5%, 56.7%, and 51.7%, respectively. The history matched oil diffusion coefficients are in the range of ten to the power of negative seven, and are in close relation with the remaining oil composition.
Carlsen, Mathias (Whitson) | Whitson, Curtis (Whitson) | Dahouk, Mohamad Majzoub (Whitson) | Younus, Bilal (Whitson) | Yusra, Ilina (Whitson) | Kerr, Erich (EP Energy) | Nohavitza, Jack (EP Energy) | Thuesen, Matthew (EP Energy) | Drozd, John (EP Energy) | Ambrose, Ray (EP Energy) | Mydland, Stian (NTNU)
The objective of this paper is to help understand the mechanisms behind gas-based enhanced oil recovery (EOR) seen in actual field performance. This is accomplished by computing and interpreting daily wellstream compositions obtained from production data during the production period(s) of Huff-n-Puff (HnP) wells in the Eagle Ford, together with relevant PVT and numerical modeling studies.
Wellstream compositions are determined from readily available production data using an equation of state (EOS) model and measured oil and gas properties obtained from sampling at the wellhead. The wellstream composition is estimated daily in one of the following two ways: (1) if measured properties from field sampling are available, then regress to find a wellstream composition that matches all the measured oil and gas properties (e.g. stock-tank oil API, gas specific gravity, GOR, and separator fluid compositions). (2) if no measured properties from field sampling are available, then flash the most-recent wellstream composition estimated from (1) and recombine the resulting oil and gas streams to match the producing GOR.
Multiple lab-scale HnP EOR experiments and associated results have been published earlier, but only limited amounts of compositional data have been presented. In this study, we attempt to link produced wellstream compositions with simulated laboratory compositions reflecting different EOR recovery mechanisms. These results should enhance the understanding of the HnP EOR mechanisms to further optimize injection and production strategies, ultimately leading to higher recoveries. The data and observations from this analysis are presented in detail. The wellstream compositions before and after HnP implementation are shown and interpreted.
By providing daily estimates of oil and gas compositions, the compositional tracking technology presented in this paper can be used as a tool to understand key mechanisms behind the reported uplift seen in EOR in unconventional resources. The identification of these mechanisms is important for companies that are implementing EOR, because it allows them to optimize their EOR strategies, target higher recoveries, and increase the technical certainty in reserve booking.
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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.