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2016 Spring WorkshopPetrophysics of the Spraberry-Wolfcamp play in the Midland basin The Denver Well Logging Society invites you to attend our 2016 Spring workshop being held Thursday, April 21st, 2016 at the Colorado School of Mines. Note the registration deadline has been extended until Thursday, April 7th. Overview: In continuation of the DWLS' workshop tradition, this spring's workshop, Petrophysics of the Spraberry-Wolfcamp play in the Midland basin, will be held from 7:30 am to 5:00 pm on Thursday, April 21st at the Colorado School of Mines. Join us for an all-day workshop focusing on new the Spraberry-Wolfcamp play in the Midland basin. Instructors:
When: Thursday, April 21st, 2016 Where: Student Center (1600 Maple St) Registration: Reservations for non-DWLS members is $225, and can be made by clicking here:
DWLS members in good standing as of January 1st and students are eligible for a discount - you should have received a special email or flyer with this discount information. If you are unemployed, you may contact us about a discounted rate. To pay by check contact Lisa Gregor at or call 303-770-4235. Payment must be received no later than Thursday, March 31st 2016; after that date, we will release your space reservation. Reservations must be made in advance, walk-ins will not be admitted! If paying by check, make it out to the DWLS, and mail it to (checks must be received by March 31st): Dominic Holmes Cancellations: Cancellations with a full refund can be made up until the March 31st deadline by contacting Lisa. After that date, no refunds will be made, however, you may send someone else as your replacement (please notify us beforehand). Abstracts: Early Permian basinal mudrocks in the Southern Midland basin – foundation for the Wolfberry PlayRobert W. Baumgardner, Texas Bureau of Economic GeologyThe Wolfberry play combines favorable geology with innovative completion practices to form one of the largest unconventional oil plays in the United States. Abundant organic carbon, brittle calcareous mudrock, and thin permeable beds form the geologic basis for the play. The Wolfberry concept grew out of preexisting plays in low-permeability sandstones (Spraberry Formation) and detrital carbonates (Wolfcamp interval) and developed in the early 2000’s through the application of modern hydraulic-fracture stimulation technology and refinement of geologic understanding of the reservoir-source-rock system. Lower Permian (Wolfcampian and Leonardian) stratigraphy in the Midland Basin records deposition in an intracratonic, deep-water basin surrounded by shallow-water carbonate platforms. On the basin floor turbidite/debrite depositional systems alternate with hemipelagic depositional systems in laterally persistent layers. Along the platform margins, slope depositional systems comprise carbonate-dominated clinoforms. By flooding or exposing the wide flanking platforms, sea-level fluctuation controlled sediment input into the basin. During inferred sea-level lowstands, platforms were exposed, and siliciclastic sediment was transported directly into the basin. During sea-level highstands, flooded platforms became carbonate factories and sediment input to the basin shifted toward platform-derived carbonate. Hemipelagic sediment was deposited throughout the sea-level cycle, contributing organic matter as well as silt- and clay-sized siliciclastics and bioclasts. Siliciclastic intervals include the lower Wolfcamp interval, the Dean Formation, and the lower and upper intervals of the Spraberry Formation. These inferred lowstand intervals comprise submarine fans that extend over 150 mi north-south and cover the basin floor. Spraberry and Dean sandstone turbidites are composed of sediment derived from source areas in the north. Hence, permeable sandstones thin southward, grading into low-permeability turbidite lobes and sheets. The lower Wolfcamp interval thins north and west away from source areas to the south and east. Calcareous intervals include the upper Wolfcamp interval, lower and middle Leonard intervals, and middle interval of the Spraberry Formation. These inferred highstand intervals are composed of hemipelagic deposits (siliceous and calcareous mudrocks) and detrital carbonate mass-flow deposits. Basinal calcareous intervals are typically thicker, coarser grained, and more permeable near the platforms that supplied the carbonate detritus. In basin-center areas calcareous intervals are mudrock dominated but include numerous thin, permeable interbeds. Wolfberry basinal deposits are oil rich, but most lithofacies are relatively impermeable. Mudrocks are organic rich (up to 6.8% TOC), thermally mature (%Roe=0.7-1.1), and oil prone. Sandstones and carbonates are mostly thin and of poor reservoir quality. The Wolfberry reservoir-source-rock system, however, is more than 2,000 feet thick, and by means of massive, multi-stage, hydraulic-fracture stimulation treatments, large volumes of marginal reservoirs are accessed and produced. Wolfcamp Midland: can the trajectory continue?Reed Olmstead, IHS EnergyThe Midland Basin Wolfcamp continues to attract investment and interest despite market conditions. The play has seen activity from 225 operators, though less than 60 are currently active. With attractive economics, a large inventory of drilling possibilities, and a growing production base, the Wolfcamp Midland is poised to be a strong contributor to domestic supply. In this presentation, we will discuss the operators currently active in the play, recent operational and development trends, and our production outlook. Petrophysical analysis of the Wolfcamp Shale IntervalMichael Holmes (Digital Formation)A petrophysical model is presented that quantifies “free shale porosity” defined as porosity separate from total organic carbon porosity, and containing mobile hydrocarbons. Volumes of likely net accessible hydrocarbons within the small volumes of free shale porosity can be quantified. Examples are presented showing the varying development of free shale porosity from well to well, and within the different stratigraphic layers of the Wolfcamp shales. Comprehensive Integrated Petrophysical Analysis That Enhances Performance of a Wolfberry PlayTim McGinley (Laredo Petroleum)Optimal petrophysical evaluations of shale plays require advanced logging programs with appropriate core studies. 3D seismic, micro-seismic, DFIT, and frac job analysis provide additional insight into what impacts reservoir performance. A probabilistic evaluation model, tied to extensive core analysis, identifies critical rock properties that will optimize production. Dipole Sonic mechanical properties computations, with frac job response integration, provide quality stress gradient and brittleness estimates. Image logs identify many geologic features and promote high quality depth control of core samples. With this technology added to the tool box, comprehensive analyses are utilized to create a strong development program. Organic Mudstone Petrophysics: A Novel Workflow To Estimate Storage CapacityKent Newsham (Oxy)The emergence of shale and oil plays in North America has caused the industry to re-examine the methods which we use to quantify the resource and recoverable reserves in place. We recognize that unconventional gas and oil reservoirs are geologically and petrophysically heterogeneous at a variety of scales. Organic mudstone systems exhibit storage and flow characteristics which are uniquely tied to nano-scale pore throat and pore size distribution and possess common organic and clay content. Appraisal of these system is also challenged by the complex fluid compositions and distribution. We present a novel workflow and methods for systematically modeling reservoirs with complex mineral and fluid composition. One of the primary objectives is for consistent and improved accuracy of reservoir storage capacity estimates. The workflow provides direct core to log calibration of static properties throughout the workflow. It also allows for calibration to dynamic properties such as pore pressure and fluid phase properties via PVT tests using industry standard correlations such as Standing and Vasquez and Beggs. The log calibration process utilized is a “hybrid” simultaneous inversion approach in which direct measurements of total clay content, total organic carbon (TOC) and pyrite from core or cuttings are used as inputs to constrain the inversion process. Other inputs are conventional log data, whose response is affected by the presence of fluids (hydrocarbons and water) and various minerals, and organic material. Results from the inversion calculations, including volumes of other rock constituents, are compared against physical measurements from core and/or cuttings. Numerous examples will be presented. Core-Log Integration Techniques for the Development of a Petrophysical Model for the Wolfcamp, Midland BasinRandy Miller (Core Laboratories)The Wolfcamp section in the Midland Basin is a major target for oil production from horizontal wells. The prospective section is over 1000 feet thick and is typically subdivided into four intervals designated as the A, B, C and D, all of which have been the target of horizontals. The Wolfcamp is stratigraphically very heterogeneous being comprised of organic mudstones thinly to thickly interbedded with tight carbonate debrites and turbidites, and in some cases siliciclastics. Core analysis data reveal that the majority of the liquid hydrocarbons reside in the organic mudstones (source rocks). In addition, the wells commonly produce water in excess of load recovery. Petrophysics in the Wolfcamp is very challenging due to 1) thin bed effects, 2) variations in matrix density, 3) identifying the source(s) or water production, and 4) determining moveable oil. In order to address these challenges Core Lab has analyzed 100 Wolfcamp cored pilot wells in the Midland Basin and integrated the data with open-hole well logs. These integration techniques will be presented along with the results. The remaining challenges will also be discussed. An Integrated Digital Rock Physics Method for Wolfcamp Formation Core CharacterizationAnyela Morcote (InGrain)The Wolfcamp formation has variability in mineral composition, organic matter, porosity and permeability that will largely influence oil production. Using a comprehensive workflow especially design for shale characterization, it is possible to quantify these rock properties. A petrophysical model is derived in this study, which is the result of integrating whole core dual-energy X-ray CT scanning, core spectral gamma ray, SEM analysis, and 3D FIB-SEM imaging and analysis. Whole core dual energy X-ray CT imaging is carried out with a voxel resolution of about 0.3 millimeter. From the imaging, continuous high-resolution logs of bulk density (RHOB) and photoelectric factor (PEF) are calculated. Plug samples depths are selected based on RHOB and PEF which are indicator of porosity and/or organic matter, and mineralogy respectively. Plugs are X-ray CT imaged at a resolution of 40 microns/voxel and subsamples are imaged with a scanning electron microscope (SEM). The SEM high resolution images are digitally analyzed to quantify the amount of organic matter, porosity, porosity associated with organics, and high density minerals present in the samples. Subsequent sampling is performed to obtain 3D FIB-SEM (focused ion beam combined with scanning electron microscopy) volumes at a resolution of about 10-15 nanometers. Their segmentation and analysis allows us to quantify organic matter, total porosity, connected porosity, and porosity associated with organic matter. Also absolute permeability is calculated using a Lattice-Boltzmann method. Thus, integrating results and analysis of three imaging methods performed on a slabbed core from the Texas Bureau of Economic Geology (BEG) in Austin, TX, we arrive at upscaled, continuous vertical measurements of mineralogy, organic matter, total porosity, organic porosity, inter-granular porosity, and permeability. This leads to a suggested landing that will target greater porosity associated with organic material, not just higher total porosity. This strategy for selecting landing zones may improve hydrocarbon recovery and reduce associated water production. Understanding how XRF and FTIR data can be used to model petrophysical properties in cutting samples – examples from lateral wells in the Wolfcamp FormationMilly Wright (Chemostrat)For decades now elemental data have been used for regional stratigraphic correlations and to elucidate depositional settings in shale plays. However, with increased pad drilling and the need for rapid completions on multilateral wells, the regional stratigraphic application of elemental data have diminished. The changing nature of the industry has led to increased need for accurate well-bore placements and understanding of rock properties from cuttings along lateral wells in order to make more cost effective completions and post drill decisions. Elemental data, acquired through XRF analytical techniques and mineralogical data acquired via FTIR (Fourier-transform infra-red) technology can be shown to provide robust and perhaps more importantly in the currently climate, cost effective and rapid means to model paleo-environment, mineralogical and TOC utilizing cutting samples. Using a set of mineralogical parameters it is possible to assign samples (from core and cuttings) to mineral facies. In core these mineral facies can be tied to certain rock properties (such as brittleness, porosity, DTC & DTS) that can be directly measured. Working within a particular target zone, it is then possible to use facies characterization, which is readily achieved using FTIR analyses, to both tie rock properties measured in the core to cutting samples from the lateral, and to model the rock properties associated with a given facies in the lateral well bore. By combining XRF and FTIR analyses in this way it is possible to provide detailed insights into landing zone characterization. This is especially insightful where expanded log suites are not run, maximizing the amount of information that can be gathered from cutting samples from laterals penetrations before the well is completed. |
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