Braided Fluvial Reservoir Research Articles

Effects of geological heterogeneity on gas mixing during underground hydrogen storage (UHS) in braided-fluvial reservoirs

Hydrogen, as an energy carrier, is at the centre of research attention for its potential advantages over electricity to transport and store excessive renewable energy at the GW scale as part of the energy transition. To store energy at such a large scale and in a seasonal manner, energy storage technologies such as compressed air storage and high-temperature aquifer thermal storage are proposed, where Underground Hydrogen Storage (UHS) in porous reservoirs may be an important technology for hydrogen economy. Research studies suggest the necessity of using alternative gas to hydrogen as cushion gas due to the very low density at reservoir conditions and the high production cost of hydrogen. In addition, the potentially lower development cost of UHS in existing depleted natural gas reservoirs or former sites for underground gas storage compared to that of saline aquifers makes gas mixing a real possibility for future UHS operations. However, this topic is rarely studied, let alone its geological governing factors. In this study, we focus on the most likely geological settings for early UHS projects (Depleted gas fields in high permeability braided fluvial reservoirs) to understand the potential impacts of geological heterogeneity on project economics.To quantify the possible gas mixing induced by macro-scale heterogeneity and find the dominant factors that affect storage performance, in this study, we start by building synthetic high permeability water-gas reservoir model with geological characteristics of braided-fluvial systems often encountered in the oil and gas industry. Then we examine the effects of structural and litho-facies heterogeneity on gas mixing processes during typical UHS projects (10 mol% hydrogen-methane mixture as stored gas) via compositional numerical simulation. Homogeneous cases with different injection/production rates are also part of the sensitivity analysis. The cumulative days hydrogen fraction in produced stream is used as the metric for quantifying gas mixing during this process. Our results show that, compared to the homogeneous cases, macro-scale geological heterogeneity will intensify gas mixing and degrade the hydrogen fraction in the produced stream, affecting up to 15.8% of the recovery in 10 years (6% more than the homogeneous cases). Geological structure (reservoir dip angle and closure area) is a first-order determining factor above facies heterogeneity (braided channel dimensions). It determines the level of methane breakthrough during UHS projects in all the test cases, leading to contrasting gas mixing behaviors. Our study hereby provides a systematic method for evaluating gas mixing in UHS projects and facilitates future UHS techno-economic analysis.

Quantitative Prediction of Braided Sandbodies Based on Probability Fusion and Multi-Point Geostatistics

Predicting the spatial distribution of braided fluvial facies reservoirs is of paramount significance for oil and gas exploration and development. Given that seismic materials enjoy an advantage in dense spatial sampling, many methods have been proposed to predict the reservoir distribution based on different seismic attributes. Nevertheless, different seismic attributes have different sensitivities to the reservoirs, and informational redundancy between them makes it difficult to combine them effectively. Regarding reservoir modeling, multi-point geostatistics represents the distribution characteristics of the braided fluvial facies reservoirs effectively. Despite this, it is very difficult to build high-quality training images. Hence, this paper proposes a three-step method of predicting braided fluvial facies reservoirs based on probability fusion and multi-point geostatistics. Firstly, similar statistical data of modern sedimentation and field paleo-outcrops were processed under the guidance of the sedimentation pattern to construct reservoir training images suitable for the target stratum in the research area. Secondly, each linear combination of selected seismic attributes was demarcated to calculate the principal component value and work out the elementary conditional probability. Lastly, the PR probability integration approach was employed to combine all conditional probabilities and calculate the joint probability. Then the joint probability was combined with training images to build a reservoir distribution model through multi-point geostatistics. We illustrated the detailed workflow of our new method by applying it to a braided fluvial reservoir modeling case in the Bohai Bay Basin, East China. The new method reduced the error of prediction results by 32% and 46% respectively, and the error of water content by 36.5% and 60.3%. This method is a potentially effective technique to predict and characterize the reservoir spatial distribution and modeling in other oil fields with the same geological background.

Object and Pixel-Based Reservoir Modeling of a Braided Fluvial Reservoir

To assess differences between object and pixel-based reservoir modeling techniques, ten realizations of a UK Continental Shelf braided fluvial reservoir were produced using Boolean Simulation (BS) and Sequential Indicator Simulation (SIS). Various sensitivities associated with geological input data as well as with technique-specific modeling parameters were analyzed for both techniques. The resulting realizations from the object-based and pixel-based modeling efforts were assessed by visual inspection and by evaluation of the values and ranges of the single-phase effective permeability tensors, obtained through upscaling. The BS method performed well for the modeling of two types of fluvial channels, yielding well-confined channels, but failed to represent the complex interaction of these with sheetflood and other deposits present in the reservoir. SIS gave less confined channels and had great difficulty in representing the large-scale geometries of one type of channel while maintaining its appropriate proportions. Adding an SIS background to the Boolean channels, as opposed to a Boolean background, resulted in an improved distribution of sheetflood bodies. The permeability results indicated that the SIS method yielded models with much higher horizontal permeability values (20–100%) and lower horizontal anisotropy than the BS versions. By widening the channel distribution and increasing the range of azimuths, however, the BS-produced models gave results approaching the SIS behavior. For this reservoir, we chose to combine the two methods by using object-based channels and a pixel-based heterogeneous background, resulting in moderate permeability and anisotropy levels.

Abstract: Scales of Heterogeneities in Braided Fluvial Reservoirs: A Case Study of the Tango Interval, Prudhoe Bay Field, North Slope of Alaska

Abstract: Scales of Heterogeneities in Braided Fluvial Reservoirs: A Case Study of the Tango Interval, Prudhoe Bay Field, North Slope of Alaska

The Role of Geology in the Behavior and Choice of Permeability Predictors

Summary For effective flow-simulation models, it may be important to estimate permeability accurately over several scales of geological heterogeneity. Critical to the data analysis and permeability prediction are the volume of investigation and sampling interval of each petrophysical tool and how each relates to these geological scales. We examine these issues in the context of the As Sarah Field, Sirte Basin, Libya. A geological study of this braided fluvial reservoir has revealed heterogeneity at a series of scales. This geological hierarchy in turn possessed a corresponding hierarchy of permeability variation. The link between the geology and permeability was found to be very important in understanding well logs and core data and subsequent permeability upscaling. We found that the small scale (cm) permeability variability was better predicted using a flushed-zone resistivity, Rxo, tool, rather than a wireline porosity measurement. The perm-resistivity correlation was strongest when the probe permeabilities were averaged to best match the "window size" of the wireline Rxo. This behavior was explained by the geological variation present at this scale. For the larger scale geological heterogeneity, the production flowmeter highlighted discrepancies between flow data and averaged permeability. This yielded a layered sedimentological model interpretation and a change in averaging for permeability prediction at the bedset scale (ms-10 × ms).

A review of braided fluvial hydrocarbon reservoirs: the petroleum engineer’s perspective

Abstract Braided fluvial reservoirs form some of the world’s giant oilfields and are found in many petroleum provinces. At best, they have excellent characteristics, but where non-net intervals (shales and siltstones) form higher proportions, they are more difficult to appraise and develop. Geological characterization (lithological correlatability, vertical sequence and porosity/permeability variability) must be communicated effectively to the reservoir engineer, whose role is to formulate a development plan and predict the production profile for a field, and to monitor and optimise day-to-day field performance. He has at his disposal other techniques: cased hole neutron logging to monitor contact levels; well testing to determine reservoir flow capacity, boundary and layering effects; production logging to assess well inflow performance or injectivity; wireline pressure profiling, field pressure and production history analysis to define vertical permeability and to reveal reservoir compartmentalization and/or communication with aquifer or injected fluids. Computer reservoir simulation modelling, now an essential tool for management of most major fields, has provided the impetus for advances in geological reservoir characterization. The question is: how can we adequately represent braided fluvial reservoirs in such models? At one end of the spectrum, sheet sands (although laterally variable) can be adequately mapped and modelled as ‘layered’ systems based on conventional approaches. At the other are multiple low-sinuosity channel sand reservoirs which, being uncorrelatable at well spacings typical during appraisal of offshore fields, may be suitable targets for stochastic or network — type approaches. Although the behaviour of a hydrocarbon reservoir must be controlled at least in part by its sedimentological characteristics, the engineer’s view of a field may be somewhat different to that of the geologist. This is as true for braided fluvial reservoirs as for those of other environmental origin. The geologist and reservoir engineer must be fully aware of each others’ data, analytical methods and objectives in order to avoid wasted effort. In the future, despite greater computing power and better modelling software, specialist technical disciplines must not loose sight of the overall objectives of field development. Small-scale geological variability affects the viability of enhanced recovery processes such as miscible flooding. However, at the development planning stage, more generalized parameter assessments may be sufficient. Reservoir characterization at the small scale, such as geostatistical outcrop analogue studies, should be balanced by more geological involvement in the planning and interpretation of well tests, which often provide the only dynamic data available during the appraisal and development planning of offshore fields. Greater cross-disciplinary understanding of reservoir characteristics could in turn ensure that an engineer would not develop an incorrect view of a braided fluvial reservoir, perhaps by correlating shaley intervals which just happen to be present at about the same location in the section.