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Pei, Yanli (The University of Texas at Austin) | Yu, Wei (The University of Texas at Austin / Sim Tech LLC) | Sepehrnoori, Kamy (The University of Texas at Austin) | Gong, Yiwen (Sim Tech LLC / The Ohio State University) | Xie, Hongbin (Sim Tech LLC) | Wu, Kan (Texas A&M University)
The extensive depletion of the development target has triggered the demand for infill drilling in the upside target of multilayer unconventional reservoirs. To optimize the hydraulic fracturing design of newly drilled wells, we need to investigate the stress changes in the upside target induced by parent-well production. In this work, an integrated parent-child workflow is presented to model the spatial-temporal stress evolution and propose the optimal development strategy for the upside target using a data set from the Permian Basin. The stress dependence of matrix permeability and fracture conductivity is determined based on available experimental data and incorporated in our reservoir simulation with the aid of an embedded discrete fracture model (EDFM). With calibrated reservoir properties from history matching of an actual well in the development target (i.e., 3rd BS Sand), we run the finite element method (FEM) based geomechanics simulator to predict the 3D spatial-temporal evolution of the local principal stresses. A displacement discontinuity method (DDM) hydraulic fracture model is then applied to simulate the multi-cluster fracture propagation in the upside target (i.e., L2BSSh) with the updated heterogeneous stress field. Numerical results indicate that stress field redistribution associated with parent-well production not only occurs within the development target but also vertically propagates to the upside target. A smaller parent-child horizontal offset induces a severer deviation of child-fractures towards the parent wellbore, resulting in more substantial well interference and less desirable oil and gas production. The parent-child fracture overlapping ratio in our study is in 0.6 ~ 0.8 for the 400 ft horizontal offset and 0.2 ~ 0.5 for the 600 ft horizontal offset. Varying the parent-child vertical offset gives the same trend as we change the horizontal offset. But with a delayed infill time, placing child-well in different layers causes more significant variation in the ultimate recovery. Moreover, infill operations at an earlier time are less affected by parent-well depletion because of the more homogeneous stress state. The candidate locations to implement infill-wells are suggested in the end for different infill timing by co-simulation of the parent-child production. With the reservoir-geomechanics-fracture model, this work provides a general workflow to optimize the child-well completion in multilayer unconventional reservoirs. The conclusions drawn from this study are of guiding significance to the subsequent development in the Permian Basin.
Summary Understanding organic porosity and its structural development in source rock reservoirs is essential to understanding how it can influence flow properties. A field emission scanning electron microscope (FESEM) was used to study the structure of the organic matter (OM) in shale samples as maturity increases. Argon ion milling of shale samples has proven to be a very powerful tool in understanding pore systems in shale, however, artifacts from this technique have been shown to obscure the OM structure. Consequently, fresh cleavage samples were imaged in addition to the argon ion-milled samples. The presence of oil/bitumen creates a challenge to observe the OM pore system by SEM techniques. To overcome this problem eight shale samples, from six different geological formations with a maturity range from 0.66 to 1.82 %Ro equivalent were observed, before and after CO2-toluene cleaning. OM at low maturity levels (<0.7 %Ro equivalent, from T-max values) is composed of sub-spherical units, generally 7–12 nm in diameter. With increasing maturity, these spherical subunits are connected, creating a network of OM. The spaces between these particles and the spaces within the connected framework determine the OM pore sizes, shapes, and distribution. Observations made by SEM showed OM structural changes from spherical structures to a crosslinked network in the OM that may be associated with maturity. Introduction Porosity occurring within the OM of potentially oil producing shales is not as well understood as in gas producing shale plays. Understanding the OM structure in oil plays may help understand flow and porosity measurements and help resolve challenges in establishing a multiscale approach. Coring is defined as the downhole acquisition and recovery of reservoir formation material, so it is important to understand that all laboratory testing is conducted on samples in as received (AR) state which may not be in their unaltered in situ state prior to core retrieval, and it is likely that some changes have occurred during coring, sampling, and handling procedures (Handwerger et.al. 2012). Observing pore systems in oil producing plays is difficult as the pore spaces may be filled or partially filled by fluids (indigenous and/or coring fluids) which makes it difficult to distinguish OM structures by SEM techniques. For this reason, observation of shale samples needs to be performed on AR samples as well as after cleaning to better observe changes in the pore system. There are several laboratory techniques available to clean core samples and, in general, they all have positive and negative attributes. The selection of best solvents greatly depends on rock type, the ability to remove fluids, and must not react with the rock sample. The CO2-toluene (CO2-tol) core cleaner is a widely used apparatus to clean crude oil, water, and drilling mud liquids from whole core samples in preparation for porosity and permeability measurements and was used in this study for the after cleaning SEM observations. While the removal of pore filling material will increase porosity, shrinkage of the OM may also take place thus increasing porosity. In 2010 Loucks et.al. described a type of pores that appeared to be the result of OM shrinkage. SEM observation of CO2-tol cleaned samples helped to understand to what extent the OM had undergone shrinkage compared to the AR samples when using this method.
A 3,680 foot (1122 m) vertical Permian Basin well was evaluated using an integrated, multi-instrument dataset acquired while drilling to identify zones of interest for lateral targets. A total of 161 cuttings samples were analyzed to determine the mineralogical (X-Ray Diffraction; XRD), organic (programmed pyrolysis via Source Rock Analyzer), and elemental (Energy Dispersive X-Ray Fluorescence spectroscopy; ED-XRF) composition while gas in air and gas in mud samples were analyzed every foot using a quadrapole mass spectrometer and a Thermal Conductivity Detector (TCD; GC-TRACER™) respectively. Each zone identified as a potential reservoir target exhibits TOC values above 2 wt%, Total Gas (THC %) 3 to 5 times greater than the background gas, Tmax and methane content (C1%) or C1/THC values suggesting that the reservoir has reached thermal maturity for mixed type II/III kerogen type determined from Hydrogen and Oxygen Index ratios, and S1 values above 1 mg/g considered adequate for unconventional reservoir production. The zones are further evaluated based on their mechanical properties including bulk mineralogy, calculated Brittleness Index, fluid properties, C1/ROP, and Helium concentration then ranked based on the likelihood of brittle behavior and fractures present during reservoir stimulation. Additionally, conditions most favorable for extensive organic matter preservation during the time of deposition were assessed using elemental proxies such as V, Ni, Mo, and U and were evaluated to further rank each zone by statistical correlation to organic and gas values (regression; R2). Of the three zones of interest identified, Zone C spanning 650 feet of the lower Pippin, lower Wolfcamp, Cisco and Cline and specifically one narrow target Organic Zone 8 within Zone C was determined to exhibit the best mechanical, geochemical, gas saturation , and elemental characteristics among all lateral targets in the wellbore. This technique of combining sophisticated cuttings analysis with advanced gas-in-mud detection systems deployed at wellsite allowed the operator to make more informed drilling decisions by not only identifying zones of interest but also the ability to rank each zone based on the most favorable mineralogy, mechanical properties, hydrocarbon content and quality, fluid type and maturity, relative permeability, relative water saturation, and paleoredox and organic matter proxies most associated with greatest potential. Additionally, these technologies and techniques can also be employed to determine wellbore position during the build and also characterize the reservoir in the horizontal to better inform completions decisions.
Summary Calcite forms variable proportions of source-rock reservoirs ("shale plays"). Although calcite content can be quantified via petrophysical analyses, XRD, XRF and other techniques, the amount of calcite, by itself, is not enough information to predict the likely importance of these minerals for reservoir and completions quality. Four principle types of calcite can be recognized:Pelagic components, mostly foraminifera and coccoliths, form a large component of the Eagle Ford and Niobrara but other types of pelagic carbonates (e.g., tentaculitids) are common in Paleozoic source-rock plays such as the Marcellus, Carbonate "event beds" (turbidites, storm deposits, etc.) are present in the Avalon, Barnett, Vaca Muerta and other plays, In situ benthic carbonates (bivalves, corals) are present in some plays (e.g., Eagle Ford, Marcellus), and Diagenetic calcites (pore filling cements, fracture fills, replacements, etc.) are present to varying degrees in perhaps most source-rock plays. Detailed core descriptions and petrographic observations are critical for assessing the origin of the calcite. Similar concepts apply to other mineral and organic components of mudstones.