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Collaborating Authors
Texas
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...)
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)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.93)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.93)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.93)
- (12 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)
- North America > United States > Texas > Haynesville Shale Formation (0.99)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > North Dakota > Williston Basin > Bakken Shale Formation (0.99)
- (3 more...)
ABSTRACT: The problem of deducing lateral extent of sedimentary bodies of interest drives the need for a detailed depositional facies interpretation. Manual interpretation can be time-consuming and differences between interpretations made by different experts can be difficult to resolve. Automated facies interpretation methods can overcome some of these problems, but agreement between the experts' interpretation and that of the machine can be difficult to attain. Borehole resistivity images contain structural and stratigraphic information in addition to a high-resolution shallow resistivity measurement, thus offering a multitude of interpretation possibilities. A new semi-automated classification method for borehole resistivity images, called Statistical Analysis of Image Logs (SAIL), may help bridge the gap between different interpretations. SAIL is based on distributions of microresistivity and on calculating a set of variability coefficients for various scales for every point of the image, whereby the distributions of this data in the interval studied are matched to the corresponding distributions of data from facies training samples, picked in regions of calibration with core. The user involvement might be as minimal as finding a single short image sample per facies to serve as a facies training sample. With its options for lithofacies and depofacies classification, this method improves multiscale visualization and has unique capabilities to help align petrophysical and geologic interpretation. In this study, we illustrate an application of this classification method for borehole resistivity images to predict core depofacies in a deepwater depositional environment. The application consists of a three-stage process: in the first two stages, the semi-automated borehole image classification method is applied to predict a fine and a coarse sequence of facies blocks, while in the third stage, a set of geologic-based rules is applied to the two image classifications and an electrofacies classification from open-hole logs, to produce a depofacies prediction.
- Geology > Geological Subdiscipline > Stratigraphy (0.90)
- Geology > Sedimentary Geology > Depositional Environment (0.67)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.31)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- North America > United States > Texas > East Gulf Coast Tertiary Basin > Wilcox Formation (0.99)
- North America > United States > Mississippi > East Gulf Coast Tertiary Basin > Wilcox Formation (0.99)
- North America > United States > Louisiana > East Gulf Coast Tertiary Basin > Wilcox Formation (0.99)
- North America > United States > Gulf of Mexico > East Gulf Coast Tertiary Basin > Wilcox Formation (0.99)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Borehole imaging and wellbore seismic (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Artificial intelligence (1.00)
Identifying Bypassed Oil In CaÑO Limon With The Carbon/Oxygen Log
Becerra, Marta Elena (Occidental de Colombia) | Hampton, David W. (Occidental de Colombia) | Mancilla, Diana (Occidental de Colombia) | Diaz, Jules (Occidental de Colombia) | Rolon, Rafael (Occidental de Colombia) | Mackualo, Helbert (Occidental de Colombia) | Salgado, Alejandro (Occidental de Colombia) | Goddyn, Xavier (Schlumberger) | Angel, Juan (Schlumberger) | Patiño, Cesar (Ecopetrol)
ABSTRACT: Caño Limon is one of the giant fields discovered in the 1980s in Colombia. As part of the Llanos basin, the field contains many prolific sands distributed between Eocene Mirador and Upper Cretaceous, containing 29 API low GOR, with a strong fresh meteoric water edge-drive aquifer. Maintaining the current production rate in a mature field is challenging, and requires dedication from the production and geoscientist teams to locate undeveloped sands. During 2010 and 2011 the Occidental Llanos Reservoir Management Team implemented an extensive workover campaign to locate bypassed oil sands, monitor the current level of saturation, and understand current drainage and imbibitions mechanisms for each area. This campaign included logging approximately 30 wells, with pulsed neutron tools in Carbon/Oxygen mode in order to differentiate between hydrocarbons and low salinity connate water or fresh water from the aquifer. Wells in the field typically have ESP pumps with Y-tools installed. The logging tool is capable of passing through the Y-tool to acquire both yield and windows carbon-oxygen data in order to ensure an accurately computed oil saturation (So). The logging campaign has been effective in locating bypassed oil and nearly undrained sands. Based on these interpretations, the reservoir team was able to propose new producer wells. The results demonstrate that these tools are helpful in sustaining field development. The methodology is applicable in many brown fields where similar conditions exist. One of the most important factors in managing reservoirs is an accurate determination of oil saturation. The accuracy of this value is critical in tracking reservoir depletion, designing enhanced oil recovery, identifying workover strategies and understanding water injection breakthrough, especially in Caño Limon, where small variations in oil saturation can signify a large volume of hydrocarbons. This problem is complicated by variable water salinities caused by the aquifer influx.
- South America > Colombia (1.00)
- North America > United States > Texas (0.87)
- South America > Colombia > Llanos Basin (0.99)
- South America > Colombia > Arauca Department > Llanos Basin > Cano Limon Field (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- (34 more...)
Abstract: This paper uses over 60 case studies in Central and South America to show that value added opportunities can be identified by integrating formation evaluation, petrophysical rock types and flow units into a reservoir evaluation. This new method has applications for exploitation evaluations and can reduce uncertainty when identifying where water will flow or not flow. The magnitude of the uncertainty reduction is a function of the intrinsic reservoir properties (porosity, water saturation and permeability). To test this method it was used in over 60 integrated reservoir characterization studies over the last 4 years. The new flow unit method is being applied in low porosity fractured carbonates, conventional dolomite reservoirs, heavy oil-reservoirs and various other systems such as young unconsolidated sediments, structurally complex naturally fractured/vuggy carbonates, low permeability "tight" formation gas sands, diagenetically altered carbonates, complex mixed lithologies and sand-shale sequences. The ideal process includes completing core-log calibration studies on lithology (mineralogy), porosity, permeability and capillary properties. A continuous Petrophysical Rock Type (PRT) curve is a key product of the core-log integration process. A quick check is made to see if the pore geometry and capillary properties are controlling the distribution of the water saturation, by comparing the shape of the petrophysical rock type curve to the shape of the log determined water saturation curve. The addition of this graphical method is proving useful for identifying undeveloped, untested zones, additional resources and helping to explain why zones are producing water. This paper describes how integrating the MCSMLP with a petrophysical rock type analysis, Stratigraphic Modified Lorenz, and Classic Lorenz Plot into a reservoir characterization study provides information on possible controls of water saturation, interval "rock speed" (permeability divided by porosity), the upper limits to "wellbore up scaling" for reservoir simulation and valuable well operation information.
- Frequently Asked Questions (FAQ) (0.34)
- Overview > Innovation (0.34)
- Geology > Geological Subdiscipline > Stratigraphy (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.54)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.34)
- North America > United States > Utah > Uintah Basin > Wasatch Formation (0.99)
- North America > United States > Texas > East Texas Salt Basin > Cotton Valley Group Formation (0.99)
- North America > United States > Louisiana > East Texas Salt Basin > Cotton Valley Group Formation (0.99)
- (2 more...)
- 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)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Core analysis (1.00)
The Introduction Of An At-Bit Natural Gamma Ray Imaging Tool Reduces Risk Associated With Real-Time Geosteering Decisions In Coalbed Methane Horizontal Wells
Wheeler, Aaron J. (PathFinder - A Schlumberger Company) | Billings, Thomas (PathFinder - A Schlumberger Company) | Rennie, Allan (PathFinder - A Schlumberger Company) | Lee, Rick (PathFinder - A Schlumberger Company) | Little, Robert (PathFinder - A Schlumberger Company) | Huiszoon, Cornelis (PathFinder - A Schlumberger Company) | Boonen, Paul (PathFinder - A Schlumberger Company)
ABSTRACT: Logging While Drilling (LWD) measurement selection is an exercise in risk management where potential drilling hazards with or without a specific measurement are weighed against their benefits. The assessment compares value added to real-time steering decisions for the area specific character of the target reservoir, mechanical limitations of the drilling and completions assemblies and economics. LWD borehole images are commonly used to place complex, long reach lateral wells into the optimal section of the reservoir. The major advantage of the use of images is that they indicate the direction in which bed boundaries are crossed (top-down or bottom-up). Additionally, the bed dips can be calculated which aid in constructing a realistic structural model of the formations of interest. Typically, the LWD tools, including the imaging measurement(s), need to be positioned in the bottomhole assembly (BHA) above the mud motor or rotary steerable system (RSS). This results in a measurement point that is some 40 ft to 80 ft behind the bit. Considering the relatively shallow depth of investigation of most imaging measurements, the images do not represent the current position of the bit in the stratigraphy - the bit may already have drilled out of the zone before this is identified on the images. A realtime at-bit natural gamma ray imaging tool was developed as a solution to position the image measurements as close to the bit as possible to reduce the reaction time for time critical geosteering decision making processes. The new tool consists of two separate subs. An instrumented stand-alone sub containing the measurement sensors is located directly above the bit. A wireless telemetry system is used to transmit the data across the mud motor to the second sub which is connected to the bottom of the conventional MLWD toolstring.
- Europe (1.00)
- North America > United States > Texas (0.94)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.48)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
ABSTRACT: The geologic complexity of Rocky Mountain reservoirs requires innovative techniques in the acquisition and interpretation of log and core data. Similarly, petrophysical models used to determine hydrocarbons in-place and reservoir flow characteristics require innovative solutions. Fortunately, recent advances in core and log technology have enabled better formation evaluation. This paper examines log and core data used to evaluate reservoirs in the Uinta basin, which include intervals that contain hydrocarbons in the solid, liquid, and gas phases. The paraffinic Green River oil has a viscosity that is highly temperature dependent and that affects both log and core measurements. Formation mineralogy includes lacustrine dolomites and various percentages of clastic and carbonate components, as well as numerous clay types and volumes. The evaluation of the hydrocarbon volume is complicated by wettability variations from water-wet to oil-wet in the Green River formation. Resistivity-based saturation models rely on the knowledge of Archie „m‟ and „n‟ exponents, which are highly variable and difficult to obtain from core. Many of the intervals appear to be self-sourcing, which may contribute to the varying temperature and pressure gradients. Finally, permeability is often fracture dominated and depends on the fracture orientation and distribution in this tectonically-active region. It is apparent that a simple triple-combo log is not sufficient to fully understand the complexities of the Green River formation, its hydrocarbon volume, or its productivity. Advanced logging technologies, such as nuclear magnetic resonance (NMR) and dielectric along with core acquisition, and their analyses will be discussed as they pertain to the understanding of some of the unique formation characteristics previously identified. In this paper, we also describe the laboratory NMR measurements of preserved core samples performed in "fresh state" and at varying temperatures to study the effects of the paraffinic oil.
- North America > United States > Wyoming (1.00)
- North America > United States > Utah (0.86)
- North America > United States > Colorado (0.86)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.94)
- (2 more...)
- North America > United States > Wyoming > Uinta Basin (0.99)
- North America > United States > Wyoming > Green River Basin (0.99)
- North America > United States > Utah > Green River Basin (0.99)
- (35 more...)
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)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Northwest Territories > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (3 more...)
Recognition And Causes Of Low Resistivity Pay Zones In Cretaceous Clastic Reservoirs: A Case Study From An Oilfield In Northern Llanos Basin, Colombia.
Becerra, Marta Elena (Occidental de Colombia) | Hampton, David (Occidental de Colombia) | Llamosa, Oscar (Occidental de Colombia) | Perdomo, Christian (Occidental de Colombia) | Malagon, Claudia (Occidental de Colombia) | Torres, Mauricio (Occidental de Colombia) | Patiño, Cesar (Ecopetrol)
ABSTRACT: Over the years, low-resistivity pay has become recognized as a worldwide phenomenon, and is present in Cretaceous clastic reservoirs of Caricare Field, Northern Llanos Basin of Colombia. The causes of low resistivity can be explained through integration of geological, petrophysical and reservoir engineering data. Understanding the causes of low-resistivity pay would result in the recovery of reserves that would otherwise be left behind pipe. The Caricare field is currently being produced from one of the Cretaceous sands, and has been since 2006. The reservoir has a strong edge water drive. Produced oil is 33.5° API with low GOR. The reservoir sands are quartz-rich, generally medium-grained, with fine-to-medium-grained interbeds. The dominant clay is kaolinite which appears as crystallized booklets, generally filling pore spaces and replacing grains. Average porosity is 24–30%, with permeability ranging from 500mD to 2000 mD. The reservoir has a homogenous capillary pressure profile throughout the interval. The depositional environment of the Caricare field is interpreted to be shallow marine. Two predominant marine facies have been recognized: a shoreface facies, containing coarsening upward sequences in the southwest part of the field; and a tidal channel facies, containing blocky to fining upward sequences, in the central to the north parts of the field. Oil productive zones in the southwest of Caricare are usually indentified as having resistivity values ranging from 20–30 ohm-m. However, the same intervals in the central and north of Caricare have lower resistivities, around 5–14 ohm-m, which calculates high water saturations. In numerous fields around the world, clays formed during and after deposition is the primary cause of low-resistivity pay. The core samples from CC-5 well showed oil saturations in zones previously calculated as non-pay intervals. The zone was tested and initially produced oil with moderate water cuts.
- South America > Colombia (1.00)
- North America > United States > Texas (0.46)
- Geology > Sedimentary Geology (1.00)
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.31)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.31)
- South America > Colombia > Llanos Basin > Gacheta Formation (0.99)
- South America > Colombia > Arauca Department > Llanos Basin > Cano Limon Field (0.99)
- South America > Argentina > Salta > Noroeste Basin > Limon Field (0.99)
- (28 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Core analysis (0.88)
- Reservoir Description and Dynamics > Reservoir Characterization > Faults and fracture characterization (0.88)