Deepak Devegowda

A Fully-Coupled Free and Adsorptive Phase Transport Model for Shale Gas Reservoirs Including Non-Darcy Flow Effects

Accurate modeling of gas through shale-gas reservoirs characterized by nano-meter pores where the effects of various non-Darcy flow regimes and the adsorbed-layer are important is presented and demonstrated by several examples. Quantification of gas transport may be accomplished using the transport equation that is valid for all flow regimes. This equation though needs further modification when transport is through a media where the gas is adsorbed onto the pore wall. In the presence of adsorption, there is a pore pressure dependent loss of porosity and cross-sectional area to free gas transport. The apparent gas permeability correction is accomplished for various flow regimes using the Knudsen number by consideration of the reduction of the cross-sectional area to free gas transport in the presence of adsorption. We show that transport in the adsorbed layer may contribute significantly in the total gas transport in these nanopores. An effective transport model is presented to account for the impact of adsorption through two mechanisms. First, we modify the transport equation to account for the pore-pressure dependent-reduction in the volume available to free gas transport; second, we model transport through the adsorbed layer using Fick’s law of diffusion. The coupled model is then compared to conventional transport models over a wide range of reservoir properties and conditions.

EFFICIENT AND ROBUST RESERVOIR MODEL UPDATING USING ENSEMBLE KALMAN FILTER WITH SENSITIVITY-BASED COVARIANCE LOCALIZATION

Recently Ensemble Kalman Filtering (EnKF) has gained increasing attention for history matching and continuous reservoir model updating using data from permanent downhole sensors. It is a sequential Monte-Carlo approach that works with an ensemble of reservoir models. Specifically, the method utilizes cross-covariances between measurements and model parameters estimated from the ensemble. For practical field applications, the ensemble size needs to be kept small for computational efficiency. However, this leads to poor approximations of the cross-covariance matrix, resulting in loss of geologic realism. Specifically, the updated parameter field tends to become scattered with a loss of connectivities of extreme values such as high permeability channels and low permeability barriers, which are of special significance during reservoir characterization. We propose a novel approach to overcome this limitation of the EnKF through a ‘covariance localization’ method that utilizes sensitivities that quantify the influence of model parameters on the observed data. These sensitivities are used in the EnKF to modify the cross-covariance matrix in order to reduce unwanted influences of distant observation points on model parameter updates. In particular, streamline-based analytic sensitivities are easy to compute, require very little extra computational effort and can be obtained using either a finite difference or streamline-based flow simulator. We show that the effect of the covariance localization is to increase the effective ensemble size. But key to the success of the sensitivity-based covariance-localization is its close link to the underlying physics of flow compared to a simple distance-dependent covariance function as used in the past. This flow-relevant conditioning leads to an efficient and robust approach for history matching and continuous reservoir model updating, avoiding much of the problems in traditional EnKF associated with instabilities, parameter overshoots and loss of geologic continuity. We illustrate the power and utility of our approach using both synthetic and field applications.

Microscopic Dynamics of Water and Hydrocarbon in Shale-Kerogen Pores of Potentially Mixed-Wettability

Distribution of alkanes and water in organic pores of shale, referred to as kerogen, is essential information required for estimation of shale-reservoir oil- and gas-in-place, adsorption of hydrocarbon, and fate of frac-water. A practical modeling approach is presented for proper description of the kerogen pore systems with different mixed wettability, surface roughness, tortuous paths, and material disorder. Three kerogen models, namely activated kerogen, kerogen free of active sites, and grapheme-slit pore, with proper surface-oxidized functional groups and high-temperature-and-pressure maturation, are constructed by simulation. Distribution of octane and water in the organic pores of these models is predicted by molecular dynamics simulation. Comparison of results reveals the importance of accurate characterization of kerogen pore systems by particular pore morphology, surface activation, and pore size. The improved kerogen models provided here are shown to determine the placement, distribution, and trapping of frac-water in shale depending on the maturity of the kerogen within organic-rich shales. Copyright 2013, Society of Petroleum Engineers.

A pore scale study describing the dynamics of slickwater distribution in shale gas formations following hydraulic fracturing

Hydraulic fracturing with slickwater to stimulate shale gas wells is routinely employed to enable increased contact with larger reservoir volumes and has the advantages of lower cost, the ability to create larger and more complex fractures, less formation damage and easier cleanup. However, a common observation is that during flow back only 10 to 20% of the frac water is recovered, even though a typical stimulation job requires several million gallons of water. Although there have been some attempts to address this phenomenon, the associated theories are lacking in scientific rigor. Due to the nanoporous nature of shales where pore proximity effects and strong inter-molecular interactions may dominate, a fundamental pore-level analysis is employed in this work to better understand and leverage the dynamics of the physiochemical processes during and after fracturing. By varying pore size in organic and inorganic pores in shales, we study the dynamics of water and gas molecules, as well as that of ions. The results of our study demonstrate that the mechanics of water entrapment and the water and ions distribution are strongly linked to the pore-surface mineralogy. Understanding the placement and distribution of frac water in both organic and inorganic pores in shales will potentially help in improved forecasting of well performance and address concerns related to the contamination of groundwater resources. Copyright 2013, Society of Petroleum Engineers.

Integration of surface seismic, microseismic, and production logs for shale gas characterization: Methodology and field application

AbstractTechnologies such as horizontal drilling and multistage hydraulic fracturing are central to ensuring the viability of shale oil and gas resource development by maximizing contact with the most productive reservoir volumes. However, characterization efforts based on the use of well logs and cores, although very informative, may be associated with substantial uncertainty in interwell volumes. Consequently, this work is centered around the development of a predictive tool based on surface seismic data analysis to rapidly demarcate the most prolific reservoir volumes, to identify zones more amenable to hydraulic fracturing, and to provide a methodology to locate productive infill wells for further development. Specifically, we demonstrate that surface seismic attributes such as λρ/μρ crossplots can successfully be employed to quantitatively grade reservoir rocks in unconventional plays. We also investigate the role of seismically inverted Poisson’s ratio as a fracability discriminator and Young’s modu...

Theoretical fundamentals, critical issues, and adequate formulation of effective shale gas and condensate reservoir simulation

The issues of relevance to describing the storage and movement of hydrocarbon gas and condensate, and water through extremely low permeability shale formations are reviewed. The shale rock is viewed as a heterogeneous quad-media continuum system. Each system has different wettability, storage, transport, and connectivity characteristics. The hydrocarbon storage is considered as being in the free gas, adsorbed gas, and dissolved gas. The alteration of fluid properties and flow behavior under pore confinement are emphasized. For gas transport the effective mean-radii and apparent permeability as a function of pore-size distribution and gas adsorption are examined. The nonequilibrium fluid distribution effect produced by tortuous narrow flow paths is discussed. It is emphasized that these form the essential phenomena that must be taken into account for effective simulation of shale gas and condensate reservoirs.

Estimation of total organic carbon and brittleness volume

AbstractThe Barnett Shale in the Fort Worth Basin is one of the most important resource plays in the USA. The total organic carbon (TOC) and brittleness can help to characterize a resource play to assist in the search for sweet spots. Higher TOC or organic content are generally associated with hydrocarbon storage and with rocks that are ductile in nature. However, brittle rocks are more amenable to fracturing with the fractures faces more resistant to proppant embedment. Productive intervals within a resource play should therefore contain a judicious mix of organics and mineralogy that lends to hydraulic fracturing. Identification of these intervals through core acquisition and laboratory-based petrophysical measurements can be accurate but expensive in comparison with wireline logging. We have estimated TOC from wireline logs using Passey’s method and attained a correlation of 60%. However, errors in the baseline interpretation can lead to inaccurate TOC. Using nonlinear regression with Passey’s TOC, nor...

Multi-objective optimization for rapid and robust optimal oilfield development under geological uncertainty

Optimal well placement is critical to oil and gas field development. Typical workflows involve procedures to place a new well or a group of new wells in a reservoir in order to maximize some pre-defined reservoir performance metric. However, there are two main drawbacks with these traditional optimization approaches: First, the impact of geological uncertainty is often neglected or there may be no framework to include geological uncertainty. Second, traditional optimization techniques normally cannot meet the requirement of optimizing two or more conflicting objectives simultaneously—this may be useful when maximizing oil recovery while also minimizing water production. Consequently, in recent years, multiple objective optimization to obtain robust solutions that minimize the decision risk under geological uncertainty becomes a topic of renewed interest. Therefore, in this work, we develop a new work flow for well placement optimization while considering geological uncertainty in reservoir models. In general, when considering geological uncertainty, the primary goal is to maximize the mean net present value (NPV) over all realizations. However, restricting the search to simply maximizing the mean NPV may be inappropriate or inadequate for decision-making. A more reasonable choice is to maximize the mean NPV while minimizing the spread of the optimal NPV’s obtained for each realization. Therefore, in this work, we apply multi-objective optimization techniques to maximize the mean and minimize the variance of NPV values over all geological realizations to provide robust well placement solutions for decision-makers to select according to their risk attitude towards field development plans.

Introduction to special section: Pattern recognition and machine learning

The E&P community, both in the industry and academia, is painfully aware of the challenges and complexity of performing seismic interpretation and reservoir characterization in increasingly larger, more intricate, and more heterogeneous data sets. This increase in size is coupled with an emphasis on

A Pore Scale Study of Slickwater Systems in Shale Reservoirs: Implications for Frac-Water Distribution and Produced Water Salinity

Pore-level molecular dynamics simulation studies are conducted towards an understanding of poor recovery of fracwater, progressive increase in produced water salinity, and identification of potential trapping mechanisms for fracwater and its influence on long-term well productivity in shale gas and oil reservoirs. The kerogen pores of shales are respesented by two organic pore models. The first model containing only carbon is intended to mimic the nature of highly mature kerogen. The second model helps understanding of the fluid behavior in partially mature shales containining oxygenated functional groups with non-zero oxygen to carbon ratio. The maturation processes of these kerogen models are described by means of a molecular dynamics simulation. These models are shown to describe effectively the essential structural features obseved in SEM images which indicate surface roughness, tortuous paths, material disorders, and imperfect pore openings of kerogen pores, and are therefore superior to the frequently assumed graphene slit pore systems. The effect of maturation, pore surface mineralogy, and pore roughness on the wettability characteristics of organic kerogen pores is delineated. Distribution of saline water in organic and inorganic pores is described as a function of pore size and morphology. These pore-scale studies reveal important insights about the distribution of dissolved ions and water in organic pores, and the frac-water distribution and produced water salinity following hydraulic fracturing. Introduction Shale gas and oil development activities have continually undergone several stages of refinement and continues to be driven by our ability to create extensive multi-stage hydraulic fracture treatments along several thousands of feet of horizontal laterals. Although these efforts have largely progressed successfully, unfortunately, our current understanding of the complex interplay of hydrocarbons and water in organic and inorganic shale nanopores is rather limited. Among the key questions remaining unanswered are related to the explanation of the poor recovery of frac-water, the progressive increase in produced water salinity, and the potential trapping mechanisms for frac-water and its influence on long-term well productivity. Shale formations are characterized by extremely low permeabilities in the orders of nanodarcies. Therefore, hydraulic fracturing treatments in combination with horizontal well completions are necessary to contact large volumes of the reservoir and to enhance well productivity. There are several field observations linked to the recovery of frac-fluids such as slickwater and the salinity of produced water. Generally, the recovery of slickwater is very low, even though several million gallons of fluid is initially injected to hydraulically fracture the well. This recovery may range from as little as 5% in the Haynesville shale to as much as 50% in the Barnett and Marcellus shales (King 2012). Additionally, we generally observe an increasing salinity of produced water over time. Even though the original injected slickwater is fresh, the salt concentration can be as high as 80,000 to 100,000 ppm at later times (King 2010). A better understanding of these issues may enable us to design better fracture treatments, to URTeC 2013 Page 1284