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Summary Developing an understanding of reservoir architecture and fluid connectivity is a challenging, but essential task for well, reservoir and facilities management (WRFM). Insight into fluid connectivity (both static and dynamic) can be obtained from molecular fingerprinting of crude oil samples. Oil fingerprinting is also applied for allocation of commingled fluid streams, and in time-lapse mode it can even help to understand fluid flow in the subsurface. Results from fingerprinting studies are directly used as constraints for static and dynamic reservoir models. A basic requirement for most fingerprinting applications is an understanding of the initial, pre-production fluid distribution. The limited availability of pre-production fluids has until now been a major constraint for the widespread application of oil fingerprinting in the industry. Reservoir rock samples contain enough residual hydrocarbons for fluid fingerprinting. Reservoir core and cuttings samples are widely available and thus provide an excellent opportunity to increase the spatial coverage of fluid fingerprints in a reservoir. A major challenge, however, is the accuracy and reproducibility of existing fingerprinting methods, which are insufficient in the chromatographic range of the ‘heavier’, non-volatile, hydrocarbons remaining in reservoir rock samples. This paper describes the application of a new, high resolution, molecular fingerprinting technology that resolves these limitations. This so-called Compound Class Specific Fingerprinting (CCSF) technique has unprecedented accuracy and reproducibility over the full analytical window, which makes it suitable for fingerprinting of both oils and extracts. An added benefit of this approach is that the additional compound class information may help to resolve why fluids are different, as not all differences are related to reservoir connectivity. As a first test, the new CCSF technology has been applied to fluid samples from an offshore field in Abu Dhabi. Two specific aspects are highlighted in this paper: . Even in this highly fractured zone, a barrier to vertical fluid flow was identified between the top reservoir and the three underlying reservoirs, which contain slightly different oil. The improved resolution of the CCSF method, combined with the molecular information it provides, made it possible to demonstrate that the fluids in the lower reservoirs are vertically connected and that gravity segregation has created a compositional gradient. These conclusions could not have been reached with existing fingerprinting technologies. . Some of the reservoirs in this field show strong compositional gradients related to the complex charge history and incomplete fluid mixing. Fluid surveillance of the mid-flank producers will help identify the efficiency of the gas and water injection schemes that are simultaneously applied to this reservoir. In addition, fluid surveillance will help to predict water and/or gas breakthrough.
Han, Hongxue (University of Waterloo) | Dusseault, Maurice B. (University of Waterloo (Corresponding author) | Yin, Shunde (email: firstname.lastname@example.org)) | Xia, Guowei (University of Waterloo) | Peng, Mingchao (Terralog Technologies Inc.)
Summary We introduce a quick and cost-effective method of estimating horizontal in-situ stress profiles and rock elastic moduli vs. depth from geophysical logs taken in vertical well sections. A multiobjective optimization approach finds the optimum solution for the inversion of in-situ stresses and the rock mechanical parameters from elastic borehole deformations measured by the commonly available four-arm caliper tools. The four-arm caliper log responses also permit quality control (QC) of input and identification and classification of borehole sections that display breakouts and sloughing. The method is applied in the estimation of horizontal in-situ stress profiles and rock deformation moduli vs. depth in Karamay Basin, Northwestern China. The results have demonstrated good agreement with available field in-situ stress measurements, indicating promising broader applications of the method.
Abstract Brazilian Pre-salts fields lie in approximately 2200 m w.d. in a challenging environment and are often characterized by highly corrosive produced fluids that pushed to the extreme the application of the most advanced material technology and engineering. Nevertheless, Lula, Sapinhoá, Mero and Búzios are definitively world-class prospects with production rates that may exceed 30.000 barrels per day per well. The development scheme of the Pre-salt fields followed the experience and the track record of the large number of deepwater fields that were previously developed in Brazil, in the post-salt regions, and is based on satellite wells tied to the floating production platform by means of dedicated production and service risers (i.e. each well has dedicated production and service lines). This satellite configuration offers the advantage to be simple, straightforward and resilient to field layout changes even during the project execution phase. However, the continuous pressure to which the Oil & Gas industry is exposed in order to increase profitability, reduce cost and, more recently, green house gas emission is encouraging Operators to evaluate different field architectures that are more traditionally implemented in other deepwater provinces outside Brazil and that the recent technology and construction asset developments made suitable also for a potential application in the Pre-salt fields. Moreover, those field architectures that are normally based on commingling of wells production are also prone to provide a faster production ramp-up and a reduced time to break even. This paper presents a description of possible Daisy Chain and Manifold-Based subsea architectures that are suitable to be applied to Brazilian pre-salt fields. The pros and cons of these alternative subsea layouts are explored. Additionally, cost and schedule analyses are presented to show the benefits of such architecture regarding CAPEX and ramp-up compared to satellite architecture, considering the "Brazilian pre-salt" scenario. Finally, a generic proposal for subsea architecture is presented for pre-salt developments jointly with practical solutions for typical operation demands related to flow assurance issues like, for instance, wax and hydrate management.
If pore volume contraction contributes prominently to overall expansion while the reservoir is saturated, then the reservoir is classified as a compaction drive. Compaction drive oil reservoirs are supplemented by solution gas drive if the reservoir falls below the bubblepoint; they may or may not be supplemented by a water or gas cap drive. Compaction drives characteristically exhibit elevated rock compressibilities, often 10 to 50 times greater than normal. Rock compressibility is called pore volume (PV), or pore, compressibility and is expressed in units of PV change per unit PV per unit pressure change. Rock compressibility is a function of pressure.
Abstract Objectives/Scope: The goal of the work is to present a depositional and reservoir model for the Three Forks Formation of the Williston Basin. Analyzing the stratigraphy, core oil and water saturations, and petrophysical analysis aid in model creation. The Three Forks is a silty dolostone throughout much of its stratigraphic interval. The problem of reserve calculation is solved by an integrated approach. Methods/Procedures/Processes: Methods include analyzing core data and performing core descriptions. In addition, petrophysics (unconventional log analysis) including nuclear magnetic logs and pulsed neutron logs help delineate productive zones in the Three Forks Formation. Mineralogy is assessed with logs, XRD, and XRF data. Source rock maturity of the lower Bakken shale also helps define the Three Forks producing fairway. Results/Observations/Conclusions: The Bakken-Three Forks petroleum system is characterized by low-porosity and permeability reservoirs in the middle Bakken, Pronghorn, and Three Forks, organic-rich source rocks (lower and upper Bakken Shales), and regional hydrocarbon charge. The Three Forks has an intimate relationship with source rock maturity in the lower Bakken shale. Reservoir facies, source rock maturity, and overpressure are key geologic factors for success in the Three Forks. Important technological factors include lateral length, lateral direction, fracture stimulation stages, amount of proppant, type of fracturing fluid, etc. Migration of hydrocarbons from thermally mature lower Bakken shales is downward into the underlying Three Forks Formation. Applications/Significance/Novelty: The Three Forks producing area is a continuous accumulation. The limits of the play are expanding with step out drilling and existing fields have merged. Downward migration of hydrocarbons can be significant in unconventional plays. Interdisciplinary Components: Geology and petrophysical approach are needed to characterize Three Forks reservoirs. Core analyses and descriptions combined with NMR and ECS logs help delineate the reservoir for accurate oil in place calculations. Introduction The Mississippian-Devonian Bakken Petroleum System of the Williston Basin is characterized by low-porosity and permeability reservoirs, organic-rich source rocks, and regional hydrocarbon charge. The unconventional play is the current focus of exploration and development activity by many operators. The Bakken petroleum system is a giant continuous accumulation in the Williston Basin (Sonnenberg et al., 2017; Sonnenberg, 2020). The structure of the Williston Basin at the top of the Three Forks is illustrated by Figure 1. The basin is semi-circular in shape and prominent structural features are the Nesson, Billings, Little Knife, Poplar and Cedar Creek anticlines. Many of the structural features have a documented ancestral origin and influenced Paleozoic sedimentary patterns (Gerhard et al., 1990). Recurrent movement on Precambrian faults or shear zones is seen elsewhere in the Rocky Mountain region (Weimer, 1980). The Nesson anticline is the location of the first oil discoveries in the 1950s. The first oil production on the Nesson anticline was from the Silurian Interlake Formation in 1951 and subsequent oil production was established from the Mississippian Madison Group.
Abstract Total Organic Carbon (TOC) content represents the weight percent of organic matter present in source rocks. The TOC content is a key petrophysical parameter for evaluating the quality of a reservoir that can be measured from core samples in the laboratory. However, these core samples are usually obtained from sparsely distributed wells, which lack spatial distribution information. This research focuses on estimating the spatial distribution of the TOC content of Bakken Shale Formation at Kevin-Sunburst dome, north-central Montana by integrating seismic and well-log datasets with a machine learning workflow. Acoustic Impedance was derived from Post-Stack Seismic Inversion using an extracted wavelet from Danielson 33-17 well. The seismic attributes derived from Seismic Inversion as well as computed TOC from Passey's method were used to train the models applied in the Multi-Attribute Analysis. The best seismic attributes were the Second Derivative of the Envelope Peak and Instantaneous Frequency. Probabilistic Neural Network improved the training correlation of the Multi-Linear Regression model from 88 % to 99% to fit a non-linear relationship. The modeled TOC obtained from the Probabilistic Neural Network was applied to the entire 3-D volume to produce a TOC spatial distribution map for the target formation. TOC values ranged between 5.2 wt % to 8.4 wt %, where the highest values were observed in the deeper portions of the Bakken Shale Formation. The spatial variation in TOC content may be explained by the uneven distribution and differential preservation of organic matter of the Bakken Shale Formation, as well as, dilution by silicate minerals. Generally, the integration of well log analysis, Passey's TOC estimation method, Post-Stack Seismic Inversion, and Multi-Attribute Analysis immensely contributed to the delineation of portions of Bakken Shale Formation with the highest reservoir quality. Introduction Kevin-Sunburst Dome is a large structural dome formed as a culmination of the Sweetgrass Arch located in Toole County, north-central Montana, USA (Figure 1). This dome covers an area of approximately 700 square miles at the Devonian Duperow Formation stratigraphic level. It has a structural relief of 750 feet, of which the target formation, Bakken Shale Formation, constitutes one of its geological formations (Figure 2).
Heidari, M. (The University of Texas at Austin) | Nikolinakou, M. A. (The University of Texas at Austin) | Flemings, P. B. (The University of Texas at Austin) | Hudec, M. R. (The University of Texas at Austin)
ABSTRACT: We predict pore pressure and stresses from seismic velocity over a volume around a salt dome in Green Canyon 955, Gulf of Mexico. The salt dome significantly changes the magnitude and orientation of principal stresses in surrounding rocks. To account for these changes, we use the Full-Effective-Stress (FES) method. This new method uses a geomechanical model to account for stress changes caused by the salt dome and the state boundary surface of the rocks to account for the contributions of all three principal stresses to the rock velocity. In this study, we develop a 3D geomechanical model based on seismic interpretation of the salt-dome geometry and show that pore pressures, least principal stresses, and mud-weight windows that this model predicts significantly differ from those that a simplified, axisymmetric (2D) model would predict. Our study shows that the FES method with a 3D geomechanical model is necessary for accurate prediction of pore pressure and stresses from velocity near salt. 1. Introduction Accurate estimation of in situ pore pressure in geological formations is crucial for hydrocarbon exploration and production. Pore pressure affects the fracture gradient in rocks sealing hydrocarbon reservoirs, which is a control on the hydrocarbon column in the reservoir (Flemings et al., 2002). It also affects the effective stresses in the reservoirs and thus their tightness and permeability. Pore pressure is a critical input for safe and economic design of wellbores (Zoback, 2010). Pore pressure in areas under deposition is typically greater than hydrostatic pressure. As sediments are deposited, their weight causes vertical compression of underlying sediments. This compression requires expulsion of pore water from the sediment pores. Because sediments are composed mostly of low-permeability mudrocks, pore water expulsion cannot keep pace with sediment deposition; as a result, pore water bears a fraction of the weight of overlying sediments as overpressure, i.e., pore pressure in excess of hydrostatic pressure (Gibson, 1958; Terzaghi and Peck, 1948), and sediments cannot compress to the degree they would under hydrostatic pressure. The more sediments are overpressured, the more they are undercompressed.
Summary Wells are sometimes deformed due to geomechanical shear slip, which occurs on a localized slip surface, such as a bedding plane, fault, or natural fracture. This can occur in the overburden above a conventional reservoir (during production) or within an unconventional reservoir (during completion operations). Shear slip will usually deform the casing into a recognizable shape, with lateral offset and two opposite-trending bends, and ovalized cross sections. Multifinger casing caliper tools have a recognizable response to this shape and are especially useful for diagnosing well shear. Certain other tools can also provide evidence for shear deformation. Shear deformations above a depleting, compacting reservoir are usually due to slip on bedding planes. They usually occur at multiple depths and are driven by overburden bending in response to reservoir differential compaction. Shear deformations in unconventional reservoirs, for the examples studied, have been found to be caused by slip on bedding planes and natural fractures. In both cases, models, field data, and physical reasoning suggest that slip occurs primarily due to fluid pressurization of the interface. In the case of bedding plane slip, fracturing pressure greater than the vertical stress (in regions where the vertical stress is the intermediate stress) could lead to propagation of a horizontal fracture, which then slips in shear. Introduction Well shear is defined as deformation of the well (usually observed as casing deformation) due to localized geomechanical shear slip that intersects the well. Typical slipping surfaces are bedding planes, faults, and natural fractures. Shear deformations in the overburden above compacting (or inflating) conventional reservoirs, and also at the reservoir/caprock interface, have been recognized for decades. Excellent overviews of these issues can be found in Dusseault et al. (2001) and Bruno (2002). Well shear associated with conventional reservoirs typically occurs only after production operations begin, and in the case of a depleting reservoir, it is often not until many years later. Unconventional reservoirs also experience casing deformations. These deformations can occur anywhere along the lateral, although many are observed near the heel. Importantly, they occur while completion operations are underway. While there are nongeomechanical causes for some of these observed deformations, there is a growing awareness that many of these deformations are due to geomechanical shear slip (Casero and Rylance 2020).
Abstract The article presents a new method of determining the residual water content and water saturation of the Bazhenov rocks formation (unconventional reservoir), which is contingent on the synchronous thermal analysis integrated with gas FT-IR spectroscopy and mass spectroscopy. The studies were executed on extensive factual core material. The combination of thermal and spectrometric methods for the identification of gases which are released during heating of core samples facilitated to analyze the dynamics of water release and proposed methods of its separation accordingly by the degrees of connectivity.