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Collaborating Authors
Unconventional and Complex Reservoirs
ABSTRACT: Pauto Complex is part of a series of imbricated thrust sheets developed as result of the Colombian Eastern Cordillera uplifting. Mirador Formation is the producer rock being very homogeneous and clean quarzoarenite very continuos through and across the entire field. The structure has been interpreted as elongated NE-SW asymmetric anticlines bounded by east verging fore-thrust and associated back-thrust that runs parallel to the structure axis. Tectonism and a deep depositional environment played a strong role on the rock deformation and diagenesis, resulting in a very complex structural and rock quality system, where both the matrix and the natural fractures contribute to well productivity. The present work is focused on defining a methodology that allows a reliable estimation of the basic parameters of the petrophysical model (Net sand, Net Pay, Fluid Saturations, Porosity, and Permeability to support both the in-place volumes (GIIP and OIIP), and the well productivity for the Pauto Complex). The methodology is based on the integration and understanding of all available data with emphasis on the capillary pressures, core fluorescence, and well production. INTRODUCTION Pauto Field is a rich gas condensate field that produces from Mirador Formation and despite of low porosity and matrix permeability, average rates per wells exceed 2000 bopd and 30mmscfd. Although, natural fractures are present in the system, there is evident that matrix contributes as well. Pauto petrophysical model is based on extrapolated properties of the nearest field in the area (Cupiagua Field). Considering this difference and also that predicting rock quality has a direct impact on well productivity and reserves estimation, it is important to build a specific petrophysical model which includes the available core and log data in the Pauto Complex, and reflects the unique rock quality and heterogeneities of the reservoir.
- Geology > Sedimentary Geology (0.88)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.48)
- South America > Colombia > Mirador Formation (0.99)
- South America > Colombia > Casanare Department > Pauto Field (0.99)
- South America > Colombia > Casanare Department > Llanos Basin > Cupiagua Field (0.99)
- South America > Colombia > Casanare Department > Florena Field (0.99)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- (2 more...)
ABSTRACT: Tight unconventional reservoirs have become an increasingly common target for hydrocarbon production. Exploitation of these resources requires a comprehensive reservoir description and characterization program to estimate reserves, identify properties which control production and account for fracturability. Multiscale imaging studies from the whole core to the nanometer scale can aid in understanding the multiple contributions of heterogeneity, natural fracture density, pore types, pore throat connectivity, mineral and organic content to the petrophysical response and production characteristics. In this paper we present three examples of the application of multiscale imaging to challenging unconventional reservoirs; a deep clastic tight gas reservoir, a fractured basement reservoir and coal seam gas reservoir. All of these samples exhibit features at multiple scales which present major challenges to petrophysical evaluation. In all cases heterogeneity and geological rock typing is undertaken at the core scale. FIBSEM imaging can then used to reveal the nanoporous microstructure of the key intervals within the phases of the core material. Petrophysical properties (porosity, permeability, elastic moduli) can also be computed for each key phase and the data upscaled using standard techniques. The presented case histories demonstrate that multiscale imaging and modelling provides a quick complimentary method to characterize the distribution and nature of different pore types and matrix components to characterize the elastic and dynamic rock properties even on rock fragments that are not suitable for conventional core analysis. Moreover the results have the potential to enhance our understanding of petrophysical, fracturing and multiphase flow processes in challenging unconventional reservoirs with low porosities and permeabilities. INTRODUCTION In recent years significant progress has been made in the development of high resolution 3D tomographic imaging and registration techniques to directly image rock microstructures across a continuous range of length scales (from nm to cm scales).
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.68)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (0.35)
- Well Drilling > Drilling Operations > Coring, fishing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (2 more...)
Abstract: Heterogeneity of the resource-shale plays and limited knowledge about the shale petrophysical properties demand detailed core-scale characterization in order to understand field-scale measurements that have poor vertical resolution. Analyses of a set of laboratory measured petrophysical properties collected on 300 samples of the Woodford Shale from 6 wells provided an opportunity to track changes in petrophysical properties in response to thermal maturity and their effect on hydrocarbon production. Porosity, bulk density, grain density, mineralogy, acoustic velocities (Vp-fast, Vs-fast and Vs-slow), mercury injection capillary pressure along with total organic carbon content (TOC), Rock-Eval pyrolysis, and vitrinite reflectance were measured. Visual inspections were made at macroscopic-, microscopic- and scanning electron microscope-scale (SEM) in order to calibrate rock-petrophysical properties with the actual rock architecture. Mineralogically, the Woodford Shale is a silica-dominated system with very little carbonate presence. Crossplot of porosity and TOC clearly separate the lower thermal maturity (oil window) samples from higher thermal maturity (wet gas-condensate window) as porosity is lower at lower thermal maturity. Independent observations made through SEM-imaging confirm much lower organic porosity at lower thermal maturity while organic pores are the dominant pore types in all samples irrespective of thermal maturity. Crack-like pores are only observed at the oil window. Cluster analyses of TOC, porosity, clay and quartz content revealed three clusters of rocks which could be ranked as good, intermediate and poor in terms of reservoir quality. Good correlations between different petro-types with geological core descriptions, along with the good conformance between different petro-types with production data ascertain the practical applicability of such petro-typing. Introduction The Woodford Shale has long been known as the source of most of Oklahoma's hydrocarbon reserves until it emerged as resource play following the huge success of the Barnett Shale play in 2005.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- (14 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- (2 more...)
Improving Geologic Core Descriptions And Heterogeneous Rock Characterization Via Continuous Profiles of Core Properties
Suarez-Rivera, Roberto (Schlumberger Innovation Center) | Edelman, Eric (Schlumberger Innovation Center) | Handwerger, David (Schlumberger Innovation Center) | Hakami, Ahmed (Saudi Aramco) | Gathogo, Patrick (TerraTek, A Schlumberger Co)
ABSTRACT: Unconventional tight shale reservoir systems are heterogeneous at all scales. This results from multiple sequences of deposition and accumulation of sediments in time, followed by locally varying and extensive post-depositional transformations. It has been said that the textural variability in shales at the thin-section scale rivals the variability of an entire outcrop in sandstones (J. Schieber). Given their colloidal size of organic and inorganic sediments, their large surface area to volume ratio, and their high chemical potential for undergoing geochemical transformations, the resulting distribution of material properties in tight shales is highly heterogeneous. Understanding scale-dependent heterogeneity in tight shales and other unconventional reservoirs is important for hydrocarbon production and recovery. It is also important for characterization, modeling, and for extending our observations, experience and understanding from one scale (e.g., core-scale) to another (e.g., log- or seismic-scale). The presence of scale-dependent heterogeneity also poses additional important questions regarding sampling for characterization, including the number of samples needed, the adequate scale for sampling and others. Addressing and solving these questions will lead to significant progress on tight shale exploration and efficient production. This paper describes continuous measurements along the length of the core that result in significant improvements to geologic core descriptions and heterogeneous rock characterization. Using multiple high-resolution measurements (e.g., of strength, thermal conductivity, CT atomic number, and XRF mineralogy) we define the principal rock classes, with similar characteristic properties, that define the heterogeneous system. The thickness and cyclic stacking patterns of these units provide quantitative information of the depositional system and its sequences. The method also differentiates transitional contacts from abrupt contacts, and provides additional information for developing a geologic model. Although the cyclic nature of tight shale sequences is often visually apparent, the variability in properties within these sequences is only accessible by the continuous measurements.
- North America > United States (1.00)
- Asia > Middle East > Saudi Arabia (0.69)
- Asia > Middle East > Israel > Mediterranean Sea (0.24)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
- (2 more...)
Abstract: Unconventional shale reservoirs have gained significant importance in the recent years in terms of reserves and production perspective. The formation evaluation aspect of these reservoirs is still in the phase of continuous evolvement. There are several petrophysical models that have been proposed for the shale plays ranging from volumetric solutions by reproducing the measured logs to applying conventional techniques like Archie, Simandoux, etc. In this paper we propose a new physically consistent solution based on partitioning the system into kerogen and non-kerogen domains with their associated porosities. These domains are not simply an arbitrary construct: they are directly suggested by the nano-scale images that have been acquired for these shale plays. The new model follows an approach that have been used in the past for understanding other systems in which there is a heterogeneity at a scale significantly finer than the measurements. The model is based on the premise that the hydrocarbon phase occupies the kerogen-related porosity with water occupying the non-kerogen matrix porosity thereby eliminating the need to compute saturations using conventional methods. The innovative aspect to this approach is that the new model solves for the kerogen porosity created by the organic diagenesis and constrained by physically meaningful bounds. The model also successfully explains industry standard approach such as Schmoker's equation. The model has been successfully applied across all shale plays in North America and drives the data acquisition program for the unconventional shale plays. Introduction Unconventional shale plays are characterized by complex pore systems. These reservoirs usually fall under the category of reservoirs that requires hydraulic stimulation to make economic rates. The proper evaluation of shale gas reservoirs draws upon and extends the range of technologies that have been applied to clastics and carbonates as well as in source rock evaluation (Vivian, 2011).
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.95)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
Borehole Acoustic Reflection Survey (Bars) From Modern, Dipole Acoustic Logs For High-Resolution Seismic-Based Fracture Illumination And Imaging
Grae, A.D. (Shell Exploration & Production Company) | Ugueto, G.A. (Shell Exploration & Production Company) | Roberts, C.J.A. (Schlumberger) | Yamamoto, H. (Schlumberger) | Oliver, T. (Schlumberger) | Martinez, G. (Schlumberger)
ABSTRACT: Understanding the impact of natural fractures in unconventional plays has been limited by the difficulty of describing fractures and intergrading this information from different scales. On one end of the scale, we have information from seismic that can allow the visualization of large fault systems or highlight areas of high tectonic displacement. On the other end of the spectrum, the data provide from wells, image logs, core and production can allow one to map and even characterize the fractures that intersect with the wellbore. What has been missing is data that allows bridging of the gap between the large scale, as provided from seismic, to the meso- and microinformation provided by logs and core. However, with modern borehole acoustic tools, meticulous data acquisition and adaptive processing algorithms, we can generate a borehole acoustic reflection survey (BARS), thereby creating a high-resolution seismic image of fractures around the well. To accomplish this, the components of the acoustic waveform data that escape the wellbore area and are reflected off the fractures are separated and processed using new, innovative processing methods. This paper discusses the tool and subsequent processing that enables the application of this technology in unconventional reservoirs. Moreover, the paper then describes the integration and verification of this data with seismic, borehole image data, and conventional core. Finally, the paper lays out conclusions and data acquisition modifications to better leverage the complimentary BARS data. INTRODUCTION As oil and gas exploration and development moves further into unconventional plays, natural fracture detection and characterization has become more important. Some plays can leverage these natural fractures to increase a well's productivity, while in other plays the fractures can be a hindrance, acting as loss zones or creating high leakoff during fracture stimulation.
- South America (0.68)
- North America > United States > Colorado > Denver County > Denver (0.15)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Structural Geology (0.68)
- Geology > Petroleum Play Type > Unconventional Play (0.68)
- Geophysics > Seismic Surveying > Seismic Processing (1.00)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
ABSTRACT: The choice of production technologies for heavy oil reservoirs hinges on robust determination of both hydrocarbon volume and viscosity. Lateral and vertical disposition of hydrocarbon as well as variations in oil properties must be quantified along with their associated uncertainties for optimizing production strategies. This paper introduces a new approach to the characterization of heavy oil reservoirs, integrating nuclear magnetic resonance (NMR) with dielectric dispersion measurements and conventional nuclear porosity logs in a single self-consistent workflow that provides reliable fluid saturation and oil viscosity. The complementary information content and commensurate sensitive volumes of dielectric and NMR logging tools make these measurements natural choices for heavy oil evaluation. Whereas conventional resistivity-based analysis may be challenged by the fresh or variable salinity formation water in many heavy oil reservoirs, dielectric logs provide robust saturations even in fresh water environments. The method builds on recent advances in NMR viscosity estimation techniques that enable accurate viscosity determination for crude oils with viscosities ranging from tens to millions of centipoise. NMR diffusion measurements as well as relaxation time distributions can be incorporated in the analysis. The method is valid for any NMR acquisition sequence, tool design, or conveyance method and ensures that radial as well as axial responses of the respective measurements are properly considered. Monte Carlo sampling is used to derive uncertainties on fluid volumes and viscosities, which can be fed in decision-making processes that rely on these quantities. Although particular attention is paid to the integration of wireline NMR, and dielectric measurements, the method is quite general and may be adapted to conventional resistivity measurements in place of dielectric logs and LWD in place of wireline logs. Examples are presented that demonstrate the application of the method in a range of very different heavy oil reservoirs.
- South America (0.93)
- Europe (0.68)
- North America > United States > California (0.47)
- North America > United States > California > San Joaquin Basin > South Belridge Field > Tulare Formation (0.99)
- North America > United States > California > San Joaquin Basin > South Belridge Field > Diatomite Formation (0.99)
- North America > United States > California > San Joaquin Basin > Belridge Field (0.99)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
ABSTRACT: Although hydraulic fracturing and horizontal drilling are now routinely used to dramatically improve the production of hydrocarbons from unconventional shale reservoirs, there is still an urgent need for an improved understanding of the fundamental rock and fluid physics in the source shale. This understanding provides the key model to evaluate the production potential of the shale play and to interpret the logging data from various formation evaluation technologies. The current model of gas in place estimation is the summation of the adsorbed gas and free gas. In this model the adsorbed gas is approximated as a monomolecular layer of gas molecules adsorbed on the surface of the organic pores in the kerogen and the majority of free gas stays within the pores. This model does not consider the extremely favorable conditions for capillary condensation to occur in the source shale: the kerogen pores are in the range of a few to a few dozen nanometers and the pore surface is hydrocarbon wet. Capillary condensation has significant implications on permeability, gas in place estimation, and Nuclear Magnetic Resonance (NMR) signals in source rock shales. In this paper we will present the successful experimental realization of capillary condensation in source shale cores in the lab. NMR measurements were also performed on these samples and the relaxation time of the hydrocarbon inside the kerogen pores was obtained. We will also present experimental results of the effects of pore size and surface wettability on the NMR relaxation time for the hydrocarbon and water signals in source rock shales. INTRODUCTION There are many new technologies applied to exploration and exploitation of unconventional resources, for example, hydraulic fracturing and horizontal drilling are now routinely used to dramatically improve the production of hydrocarbon from shale plays (unconventional shale gas and shale oil).
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
ABSTRACT: A method is presented for determining porosity, permeability and rock mechanic properties from drill cuttings collected in horizontal wells, with a view to improve the design of multi-stage hydraulic fracturing in tight gas formations. As time is of the essence, key to the proposed approach is optimizing the design time between the moment in which the cuttings are collected and the moment in which the hydraulic fracturing job is to be performed. This is critical as the work involves experimental work with cuttings in the laboratory, analytical calculations, stimulation design with a 3D hydraulic fracturing simulator and developing of recommendations as to where to stimulate the horizontal well. Drill cuttings are powerful sources of information that have been used for several decades by well site petroleum geologists for qualitative evaluation of reservoir rocks. Additional cuttings work is carried out subsequently in the laboratory. This includes, for example, the preparation of thin sections for petrographic work and the evaluation of microfractures and slot porosity in the case to tight gas formations. Drill cuttings, however, have not been used to full advantage in the case of hydraulic fracturing jobs. This study shows that, although imperfect, drill cuttings are important direct sources of information that can help to improve results in multi-stage hydraulic fracturing jobs. In addition to qualitative analysis, cuttings can be evaluated quantitatively to provide reasonable input data for hydraulic fracturing simulators during the design stage. This becomes even more important as the amount of collected information in horizontal wells, including well logs, is rather limited in most instances, although all wells in formations with fraction of millidarcy permeability require some type of stimulation. It is concluded that information extracted from drill cuttings can be used to determine optimum locations for hydraulically fracturing of horizontal wells.
- North America > Canada > Alberta (0.71)
- North America > United States > Texas (0.46)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type (0.95)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.34)
- Well Drilling > Drilling Fluids and Materials > Cuttings transport (1.00)
- Well Completion > Hydraulic Fracturing > Multistage fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Tight gas (1.00)
ABSTRACT: Heavy oils frequently exhibit large compositional gradients. However, previously, there had been no predictive equation of state model to treat gradients in heavy oils, thereby largely precluding understanding and modeling of these gradients. Recent advances in asphaltene nanoscience include delineation of the colloidal nature of asphaltenes in crude oils including mobile heavy oils, the Yen-Mullins model. In turn this has led to the industry's first predictive asphaltene equation of state, the Flory-Huggins-Zuo EOS. For heavy oils with a low gas/oil ratio (GOR), this EOS has a very simple form. This simple model is shown to apply specifically to a heavy oil column in a producing field in Ecuador. This is the first demonstration of its kind. A large asphaltene gradient with its associated huge viscosity gradient is shown to be consistent with a vertically equilibrated distribution of asphaltenes. Simple models are given to provide a first order prediction of the viscosity gradients spanning a factor of 30. Nuclear magnetic resonance (NMR) characterization of these gradients is shown to be effective. In this field, production has resulted in large and variable pressure depletion. Nevertheless, the fluid compositional distribution in large measure appears to reflect that which existed prior to production. Fluid and pressure measurements are known to be complementary for formation evaluation prior to production. Here, we show that fluid and pressure measurements are complementary after significant production. New directions for characterization of heavy oil columns are discussed focusing on recent science and technology advances. INTRODUCTION In years past, there had been a gross deficiency in the thermodynamic modeling of crude oils. By revealing fluid complexities in real time during the wireline job, DFA enables matching the complexity and cost of such operations to the complexity of the oil column.
- Europe (0.69)
- South America (0.67)
- North America > United States > Colorado (0.28)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- (3 more...)