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Collaborating Authors
An Integrated Geomechanical, Petrophysical and Petrographical Study to Evaluate the Efficacy of a Plug Cleaning Technique for Ultra-Low Permeability Rocks
Guedez, Andreina (MetaRock Laboratories) | Govindarajan, Sudarshan (MetaRock Laboratories) | Lambert, Denton (Petricore) | Keyes, Steve (Petricore) | Patterson, Robert (MetaRock Laboratories) | Mickelson, William (MetaRock Laboratories) | Mitra, Abhijit (MetaRock Laboratories) | Aldin, Samuel (MetaRock Laboratories) | Gokaraju, Deepak (MetaRock Laboratories) | Thombare, Akshay (MetaRock Laboratories) | Aldin, Munir (MetaRock Laboratories)
Abstract Core analysis practices recommend removal of residual fluids before laboratory measurements of porosity, permeability, and fluid saturations. The most common methods used for core cleaning are Dean-Stark and Soxhlet extraction. While these techniques are adequate for conventional rocks, they are -a) time consuming and b) may induce micro-fractures in unconventionals with ultra-low permeability, thus affecting permeability and porosity measurement. In order to reduce the cost and time of fluid extraction and measuring permeability for such rocks, the GRI crushed-rock technique was proposed. However, the crushing process may destroy connected micro-pores which would not be accounted for in subsequent measurements. A cleaning method for ultra-low permeability rocks involving multiple cycles of pressurized CO2 driven extraction has been previously proposed. The method employs automated gradual pressure release to avoid parting or fracturing the weak planes or the rock matrix during the CO2 phase change. However, it is critical to ascertain that the permeability increase is resulting from removal of fluids alone and not due to induced fractures. The paper seeks to investigate the effect of the supercritical CO2 based cleaning process on the samples. The method undertaken is a multidisciplinary look utilizing a strength index, mineralogical composition, and studying the pore attributes and oil content before and after cleaning. Brazilian tensile strength is utilized as an index and is measured on multiple plugs at the same depth to assess whether samples develop fractures during cleaning. X-Ray Diffraction (XRD) is performed to characterize minerological composition while LECO TOC method and rock-eval pyrolysis are utilized to determine oil content. Pore attribute characterization is done by Scanning Electron Microscopy (SEM) and thin section study. Source rock analysis confirmed the extraction of pore fluids. Preliminary results showed that tensile strength did not decrease significantly following fluid extraction. Comparison of the strength index before and after cleaning showed that a lower decrease in tensile strength is associated solely with the cleaning process while a bigger difference indicates presence of fractures. Additional pore attribute and mineralogical studies supported the results observed in the strength index characterization. The suggested additions to the previously proposed cleaning method address uncertainties in core cleaning and help to enable representative measurement of petrophysical properties of ultra-tight rocks. The integrated study combining strength index characterization, petrographical and source rock analysis provides a comprehensive validation method for the effectiveness of the Huff & Puff cleaning technique.
- North America > Canada (0.68)
- North America > United States > Texas (0.68)
- North America > United States > Colorado (0.47)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- (2 more...)
- 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 > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- (9 more...)
Effect of Mineral Orientation on Roughness and Toughness of Mode I Fractures
Jiang, Liyang (Purdue University) | Yoon, Hongkyu (Sandia National Laboratories) | Bobet, Antonio (Purdue University / Lyles School of Civil Engineering) | Pyrak-Nolte, Laura J. (Purdue University / Lyles School of Civil Engineering)
ABSTRACT: Anisotropy in the mechanical properties of rock is often attributed to layering or mineral texture. Here, results from a study on mode I fracturing are presented that examine the effect of layering and mineral orientation fracture toughness and roughness. Additively manufactured gypsum rock was created through 3D printing with bassanite/gypsum. The 3D printing process enabled control of the orientation of the mineral texture within the printed layers. Three-point bending (3PB) experiments were performed on the 3D printed rock with a central notch. Unlike cast gypsum, the 3D-printed gypsum exhibited ductile post-peak behavior in all cases. The experiments also showed that the mode I fracture toughness and surface roughness of the induced fracture depended on both the orientation of the bedding relative to the load and the orientation of the mineral texture relative to the layering. This study found that mineral texture orientation, chemical bond strength and layer orientation play dominant roles in the formation of mode I fractures. The uniqueness of the induced fracture roughness is a potential method for the assessment of bonding strengths in rock.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Mineral > Sulfate > Gypsum (0.95)
- Materials (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.96)
- North America > United States > New Mexico > San Juan Basin > San Juan Basin Field > Mancos Formation (0.99)
- North America > United States > Colorado > San Juan Basin > San Juan Basin Field > Mancos Formation (0.99)
ABSTRACT: Fluid flow and compressional wave propagation measurements were made on fractured samples prior to and after the chemical deposition of calcium carbonate. We observed that the initial void geometry (aperture and contact area) controlled the amount and spatial distribution of mineral deposition within the fracture. The most reliable seismic indicator that the fracture had been altered is a reduction in the width of the distribution of the most probable frequency in the received signal. A reduction in the width of the distribution indicates that the fracture is homogenized by mineral deposition in the fracture voids. Homogenization occurs because the mixing predominantly takes place in the dominant flow paths within the fracture which tend to have low fracture stiffness. The results indicate that acoustic imaging techniques are required in this characterization because they provide a statistical indicator to monitor changes in fracture geometry caused by mineral deposition. 1. INTRODUCTION The construction of underground structures can alter the underground environment by changing the local stress distribution as well as the local hydrogeology of a site. Depending on the purpose of the underground structure, long-term monitoring of underground environments may be required because fractures, joints and faults can be altered over the lifetime of the engineered structure. Because rocks are part of the tectonic and hydrogeologic cycles, the geometry of the voids and contact area in a fracture can be altered by time-dependent processes such as normal and shear displacement, weathering, chemical precipitation, and chemical dissolution. For example, CO2 injection into a subsurface reservoir can initiate a complex set of reactions that involves interactions between aqueous solutions and the minerals in the host rock. CO2 can transfer across a gas-water interface to become an aqueous ion by the reaction: (available in full paper) This is followed by rapid dissociation of carbonic acid: (available in full paper) The formation of bicarbonate ion, HCO3-, and production of acidity by release of H leads to a series of secondary reactions. These reactionscomplicate estimates of CO2 storage volumes as well as measurements of the geophysical characteristics of the rock. If minerals precipitate in a fracture or if the fracture void geometry is dissolved because of CO2 injection, the geometrical properties of the fracture will change and may alter the hydraulic and seismic properties of the fracture. In this study, we used acoustic measurements to monitor the deposition of calcium carbonate in a racture and its effect on hydraulic properties of single fractures. 2. EXPERIMENTAL METHOD 2.1. Sample Preparation Granitic samples were used to study wave propagation across a fracture prior to and after mineral precipitation within a fracture. The samples were made from Barre granite which had no connected matrix porosity. The compressional wave velocity for an intact sample (i.e., no throughgoing fractures) was 3520 m/s and the shear wave velocity was 2570 m/s. An intact ample, GI04, was used for control experiments. Four fracture samples, GF01, GF03, GF05 and GF08, were created for this investigation by inducing a single fracture in each using a technique similar to brazil testing [1].
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Geological Subdiscipline > Environmental Geology > Hydrogeology (0.54)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.35)
- Geophysics > Seismic Surveying > Seismic Processing (0.34)
Submicron-Pore Characterization of Shale Gas Plays
Elgmati, Malek (Missouri University of Science & Technology) | Zhang, Hao (Missouri University of Science & Technology) | Bai, Baojun (Missouri University of Science & Technology) | Flori, Ralph (Missouri University of Science & Technology) | Qu, Qi (Baker-Hughes Company)
Abstract Gas storage and flow behavior in the shale gas rocks are complex and hard to identify by conventional core analysis. This study integrates clustering analysis techniques from material science, petrophysics, and petrology to characterize North American shale gas samples from Utica, Haynesville, and Fayetteville shale gas plays. High pressure (up to 60,000 psi) mercury porosimetry analysis (MICP) determined the pore size distributions. A robust, detailed tomography procedure using a dual-beam (Scanning Electron Microscope and Focused Ion Beam, also called SEM-FIB) instrument successfully characterized the submicron-pore structures. SEM images revealed various types of porosities. Pores on a scale of nanometers were found in organic matter; they occupy 40โ50% of the kerogen body. Two-hundred two-dimensional SEM images were collected and stacked to reconstruct the original pore structure in a three-dimensional model. The model provided insights into the petrophysical properties of shale gas, including pore size distribution, porosity, tortuosity, and anisotropy. This paper presents the pore model constructed from Fayetteville shale sample. The work used X-ray diffraction (XRD) to semi-quantify shale gas clay and non-clay minerals. The Haynesville and Utica (Indian Castle formation) shale samples have a high illite content. The Utica (Dolgeville formation) shale samples show high calcium carbonate (calcite) content. Moreover, wettability tests were performed on the shale samples, and the effect of various fracturing fluid additives on their wettability was tested. Most additives made the shale gas surfaces hydrophilic-like (water-wet).
- North America > United States > Texas (0.94)
- North America > United States > Arkansas > Washington County > Fayetteville (0.46)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Mineral (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.67)
Abstract Creating sufficient and sustained fracture conductivity contributes directly to the success of acid fracturing treatments. The permeability and mineralogy distributions of formation rocks play significant roles in creating non-uniformly etched surfaces that can withstand high closure stress. Previous studies showed that depending on the properties of formation rock and acidizing conditions (acid selection, formation temperature, injection rate and contact time), a wide range of etching patterns (roughness, uniform, channeling) could be created that can dictate the resultant fracture conductivity. Insoluble minerals and their distribution can completely change the outcomes of acid fracturing treatments. However, most experimental studies use homogeneous rock samples such as Indiana limestones that do not represent the highly-heterogeneous features of carbonate rocks. This work studies the effect of heterogeneity, and more importantly, the distribution of insoluble rock, on acid fracture conductivity. In this research, we conducted acid fracturing experiments using both homogeneous Indiana limestone samples and heterogeneous carbonate rock samples. The Indiana limestone tests served as a baseline. The highly-heterogeneous carbonate rock samples contain several types of insoluble minerals such as quartz and various types of clays along sealed natural fractures. These minerals are distributed in the form of streaks correlated against the flow direction, or as smaller nodules. After acidizing the rock samples, these minerals acted as pillars that significantly reduced conductivity decline rate at high closure stresses. Both X-ray diffraction (XRD) and X-ray fluorescence (XRF) tests were done to pinpoint the type and location of different minerals on the fracture surfaces. A surface profilometer was also used to correlate conductivity as a function of mineralogy distribution by comparing the surface scans from after the acidizing test to the scans after the conductivity test. Theoretical models considering geostatistical correlation parameters were used to match and understand the experimental results. Results of this study showed that insoluble minerals with higher mechanical properties were not crushed at high closure stress, resulting in a less steep conductivity decline with increasing closure stress. If the acid etching creates enough conductivity, the rock sample can sustain a higher closure stress with a much lower decline rate compared with Indiana limestone samples. Fracture surfaces with insoluble mineral streaks correlated against the flow direction offer the benefit of being able to maintain conductivity at high closure stress, but not necessarily high initial conductivity. Using a fracture conductivity model with correlation length, we matched the fracture conductivity behavior for the heterogeneous samples. Fracture surfaces with mineral streaks correlated with the flow direction could increase acid fracturing conductivity significantly as compared to the case when the streak is correlated against the flow direction. The results of the study show that fracture conductivity can be optimized by taking advantage of the distribution of insoluble minerals along the fracture surface and demonstrate the important considerations to make the acid fracturing treatment successful.
- Geology > Mineral (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.88)
- Well Completion > Hydraulic Fracturing (1.00)
- Well Completion > Acidizing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Faults and fracture characterization (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)