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2020 Spring WorkshopHorizontal petrophysics: Applications and interpretation techniques in reservoir characterizationIn continuation of the DWLS' workshop tradition, next spring's workshop, Horizontal petrophysics: Applications and interpretation techniques in reservoir characterization, will be held Wednesday, April 29th, 2020 from 7:30 am to 4:00 pm at the American Mountaineering Center in Golden, CO. Overview: Join us for an all-day workshop covering:
Breakfast, box lunches, and refreshments will be provided. A printed booklet will not be provided, but an electronic booklet will be made available in advance via email. When: Wednesday, April 29th, 2020 Where: American Mountaineering Center Registration: DWLS members that were in good standing as of 1/1/2020 should have received an email on February 19th with instructions to register at the members-only reduced rate. Similarly, students should have seen an email with the students-only reduced rate. All others should register using the PayPal link below ($195):
If you are registering for someone else or using a PayPal account that is not in your name, please click here to send us an email with the correct registrant information. You should also use this link if you are registering multiple people; please provide the name, company affiliation, and email address for each registrant. If you are unemployed, you may contact us about a discounted rate. The deadline to register is Friday, April 17, 2020. Cancellations: Cancellations with a full refund can be made up until the April 17th deadline. After that date, no refunds will be made, however, you may send someone else as your replacement (please notify us beforehand using the email link above). Speakers: Anne Grau (Grau Energy) Elia Haddad (Schlumberger) Jason Edwards (Fracture ID) J Gremillion or M. Flowers (Schlumberger) Robert Laronga (Schlumberger) Alexander Kolomytsev (Gazprom) Harry Xie (CoreLab) Hui Xie (Schlumberger) Edgar Velez (Schlumberger) Nigel Clegg (Halliburton) Farhan Alimahomed (Schlumberger) Patricia Rodrigues (Whiting) Abstracts: Anne Grau (Grau
Energy) Eleven wells in the DJ Basin were drilled utilizing acquired-while-drilling (AWD) Geochemistry in an effort to aid real-time geosteering in optimum rock quality, to provide petrophysical characterization useful to completion design, and to identify geohazards and fluid compartmentalization. The data collected from this effort profoundly improved the ability to geosteer in the best target consistently, to accurately quantify ‘in-zone’ statistics for the program, and was immediately relevant and incorporated into completion design. Additionally, geochemical signatures for subseismic faults and fractures were detected, along with clear identification of stratigraphic location of the borehole. Organic matter quality and thermal maturity data gleaned from cuttings provided a characterization of the hydrocarbon product which was synthesized with thermal maturity mapping and well performance. The acquisition of these data were found to be safer to run than horizontal wireline logs, while providing more detailed petrophysical characterization. In a pilot study two extended reach laterals, one Niobrara C well and one Codell well, were drilled in 2017, with samples collected every 100 feet and tested for Energy-dispersive X-ray Fluorescence (ED_XRF), Bulk X-ray Diffraction (XRD), and HAWK Pyrolysis to compliment Mass Spectrometry analyzing the full hydrocarbon spectrum of C1-C12 and inorganic gasses collected while drilling. The data was synthesized after completion and four main observations were made: 1.) Mineralogical characterization using XRD along the borehole could immediately and precisely identify Rock type and stratigraphic zone of drilling (In-zone/Out of zone). 2.) Mineralogical Brittleness obtained from XRD was immediately correlated to completion issues and incorporated into completion design 3.) XRF trace elements along yielded a surprising fault and fracture indicator that also became useful to completion design 4.) Mass spectrometry also yielded interesting qualitative comparisons of hydrocarbon fluids and gases, and provided further compartmentalization characterization for each well. Together, these collected components led to a significant greater understanding of the borehole than gamma ray, cuttings, mudlogs, and horizontal logs combined.
Elia Haddad (Schlumberger) When a North American onshore operator commits to logging a horizontal well, microelectrical borehole images are by far the number one requested measurement—Why? Typically, the motivation to acquire images is the objective to understand natural fracture networks, which in the experience of many Completion Engineers exert some kind of influence upon hydraulic fracture completions. But once the natural fractures are observed, what does one do with the data? In this work we revisit the natural fracture characterization application and present strategies and workflows to leverage the data into actionable decisions that improve completion performance. We introduce additional novel applications such as facies classification and ultra-high-resolution structural cross-sections that contain just as much (or even more) insightful information into completion performance and are predictive of the mechanical and petrophysical properties intersected by the well. Lateral heterogeneity is defined as the continuous change of reservoir and mechanical properties, linked to depositional facies and local structural variation as we move away from a pilot well. It is well-documented everywhere, and begs the question “Is it valid to treat shales as a simple layer cake?” Predicting rock behavior with hydraulic fracture stimulation still remains the most challenging part of any unconventional reservoir development. Changes in depositional facies (with associated changes in petrophysical and mechanical properties) can be responsible for great variation in stimulation performance. Image logs in the lateral provide an excellent tool to classify, map, and characterize facies along lateral wells. Are fractures propagating the same way from massive, bioturbated to highly laminated facies? Depositional facies provide a better understanding and prediction to the fracking process, and it may be easier to predict their spatial distribution than it is to directly predict distribution of underlying physical properties. Localized structural change represents another challenge. Many operators pride themselves in being able to steer a well geometrically within a 30-ft zone, but anyone who has studied a set of pilot logs knows that in shales, key properties vary vertically over much shorter distances. Absent real-time 3D geosteering, perhaps the most valuable application of a microelectrical image is to construct an ultra-high-resolution structural cross section from the dips to reveal exactly where each foot of the lateral was placed in the stratigraphic column. This in turn may give rise to changes in hydraulic fracture propagation and geometry. With the structural and depositional context understood, we now revisit how best to use natural fracture information. A discrete fracture network (DFN) model is populated with image data and used to inform an unconventional hydraulic fracture modeling simulator. We predict variations in hydraulic fracture complexity and half-length along the lateral and we are able to recommend changes to the pump schedule designed to balance completion performance and assure conformance to well-spacing from heel to toe.
Jason Edwards (Fracture ID) Geologic heterogeneity in the Wolfcamp Formation in the Delaware basin plays a major role in overall well performance. This heterogeneity impacts both the completions efficiency and production. This paper presents 1) the results of integrating multiple datasets from a lateral well in the Wolfcamp and, 2) a workflow that uses completions and production data to analyze the impact of geologic complexity. Multiple data sets were acquired over a single horizontal well including wireline dipole sonic and image logs, MWD geomechanical measurements, mass spectrometry mud logs, produced fluid tracers and one-second treatment data. New analytical techniques for identifying key rock properties at the perf-cluster and stage scale highlighted which geologic parameters had the biggest impacts on completions and production performance. However, this level of data acquisition is not feasible in every wellbore; therefore, the learnings from this inclusive data set were distilled into a predictive framework using only the MWD geomechanical measurements. Results of this study indicate a significant impact of the near-wellbore mechanical properties on both completions and production results. Specifically, high HTI anisotropy within a stage led to an increase in ISIP relative to calculated minimum horizontal stress. Additionally, mechanical quality correlated to production and fluid type. Integration of these diverse measurements with fluid tracer and treatment data provide information on the role of fractures, the impact of sedimentary complexity and other causes of variability in stimulation and production results. The geomechanical properties of near-wellbore rock have important implications for drilling and completions efficiency, as well as EUR. It is, therefore, important to quantify these properties in a context that can be easily leveraged by geoscientists and engineers. The use of MWD geomechanical measurements to capture the learnings from this very robust data set and apply them to additional wells provides an economically efficient opportunity to improve both reservoir characterization and completions optimization in horizontal wells. By working closely with drilling and completions engineers, and applying these types of workflows, geoscientists can provide valuable insight across domains.
J Gremillion or M. Flowers (Schlumberger) When planning a horizontal well one of the most important decisions is choosing the measurement that will be used to steer. Which tool to select depends on the measurement contrast between the target formation and the surrounding formations, target thickness and most importantly what are the project objectives. Judiciously choosing the correct measurement can help maximizing exposure within the target window and reduce trouble time and sidetracks. Steering within unconventional reservoirs is generally done using the simplest measurements possible, the Measurements While Drilling Gamma Ray (MWD GR). This is due to cost or lack of perceived need for additional measurements, or because GR gives enough information with the large amount of offset data that exists. We looked at several case studies where tools were selected by analyzing the offset for measurement contrast and forward modeling the planned well trajectory across the zone and exiting the top and base of the target window. The first example was in the Wolfcamp A formation in the Delaware basin where the symmetry of the response of the Gamma Ray made it difficult to accurately steer using just and average GR measurement. The second example is from the Midcon region where the target reservoir had very little GR contrast with the surrounding rock and we had to determine which measurement would be most appropriate for steering there. The third and more detailed example was a series of wells in the Olmos sand found in the coastal area of south Texas. The target is a higher-porosity layer within the Olmos “C” sand, which is approximately 10 to 12 feet thick with surrounding rock is that is tighter but will produce if fractured. The project objective was to drill wells to maximize exposure in the high-porosity layer, then hydraulically fracture the reservoir. The offset log data was forward modeled, then the best measurement that would achieve project objectives was chosen and the wells drilled. Selecting the proper measurement by careful analysis beforehand allowed the wells to be steered successfully, which led to increased production compared to offset horizontals steered without an azimuthal measurement.
Robert Laronga (Schlumberger) Even as highly efficient and low-risk deployment platforms for wireline measurements have been introduced in recent years, fewer than 10 percent of lateral wells drilled in the onshore U.S. have some kind of downhole measurement other than a simple MWD gamma ray. The decision to ‘stop the drilling factory’ for a few hours to acquire needed data is not taken lightly, therefore it is a priority for us as Petrophysicists to ensure maximum value is realized from these data when the time is invested. Downhole measurements of multiphase production such as horizontal production logs combined with distributed temperature sensing and distributed vibration sensing via fiber optics are absolutely key in validating conclusions drawn from open hole logs and may in some cases strongly influence or change those conclusions. Of those laterals that are logged: although many are logged specifically to engineer a well-and-stage-specific completion design, and a few are even logged purely for geoscience data-gathering, the majority of operators logging laterals do so to ‘understand’ or ‘benchmark’ completion and well performance vs. geology and reservoir properties, and to develop actionable insights they can apply and replicate on the next batch of wells to be manufactured. Such logging programs may be combined with variations to the stage design within the same lateral. The industry holds many logical notions that have often or sometimes proven true; that within a well, rocks having more favorable reservoir properties (e.g. porosity, permeability, saturation) produce hydrocarbon at a better rate; that a stage having uniform mechanical properties will be more effectively stimulated than a stage having heterogeneous mechanical properties; or that the presence of pre-existing natural fractures may be beneficial (or detrimental) to production for example. Wellhead production alone cannot validate such conclusions, nor can it solely be used to benchmark a new completion design, because nearly all unconventional wells encounter heterogeneity along the lateral arising from facies changes and from variations in the well position in the stratigraphic column. Production is therefore never uniform along an entire lateral. Chemical tracers have become ubiquitous as one means to attempt to allocate production by stage, however the limited number of unique tracers available has not kept up with the number of stages per well. In any case, fiber optic and production logs are the only means available to allocate production to the level of the perforation cluster—and this becomes increasingly important given the industry trend toward higher and higher numbers of perforation clusters per stage. We examine case studies from the Rockies and elsewhere where both open hole and production logs and/or fiber optic data were acquired in the same lateral well, with an emphasis on how the data are integrated to draw conclusions about completion performance vis-à-vis geologic, petrophysical, and geomechanical properties.
Alexander Kolomytsev (Gazprom) Most conventional log interpretation techniques use the radial model, which was developed for vertical wells and work good in them. But applying this model to horizontal wells can result in false conclusions. The reasons for this are property changes in a vertical direction and different DOI of logging tools. DOI area probably can include a response from different layers with different properties. All this complicates petrophysical modeling. The 3D approach for HAWE is forward modeling in 3D. For this modeling, it is necessary to identify the geological concept near horizontal well using multiscale data. The accuracy of modeling depends on details of the accepted geological model, which is based on the data of borehole images, logs, geosteering inversion, and seismic data. Petrophysical properties are assigned to each layer. After that, forward modeling can be run. Synthetic curves and images are compared with real data for QC. 3D modeling can be applied in order to improve the accuracy of reservoir characterization and well completion. Often the radial model is useless for HAWE because LWD tools have different DOI and the invasion zone was not formed. Difference between volumetric and azimuthal measurements is important for comprehensive interpretation because various formations has different properties in vertical directions. Resistivity tools have the biggest DOI. It is important to understand and be able to determine the change of log response: a change in the properties of the current layer or approaching the layers with other properties. For this, it is necessary to know the distance to the boundaries of formations with various properties and, therefore, to understand the geological structure of the discovered deposits, and such information on the scale of well logs can be obtained either by modeling or by using extra deep resistivity inversion (mapping). For modeling purposes, the largest amount of multidisciplinary information is needed - from images and logs to mapping and seismic data. This approach allows to build a complete picture relying on all research methods, to understand what is connected with one or another change in properties, to connect these changes with the geological structure, sedimentology. A more accurate determination of the effective lengths and formation properties helps optimize well completion design. In wells of the field in northern part of the Western Siberia, the planned production rate from conventional log analysis differed from the actual average by 30%. 3D petrophysical approach to interpretation improved reliability by three times, reducing the discrepancy between the plan and the fact to 9%. The modeling result is the true petrophysical properties of all layers within the geological model along the horizontal section of the wellbore. These true properties can be used for quantitative interpretation in order to determine the reservoir characterization. This approach avoids errors in determining the estimated parameters that arise due to polarization effects and the influence of nearby reservoirs on the logs, optimize the well completion design and quickly update the geological model for making decisions during geosteering.
Harry Xie (CoreLab) The primary objective of this work is to find practical ways to measure characterize horizontal reservoirs using drill cuttings. In this paper, we will describe a new analytical workflow and show how petrophysical and geochemical properties can be acquired from easily obtained drill cuttings. Drill cuttings are valuable sources of samples for the determination of rock properties, especially in the cases such as horizontal wells, where coring is not available. The characterization of drilling cuttings involves several laboratory technologies including cleaning, measuring liquid porosity and saturations using high frequency (20MHz) NMR T1-T2 2-D Mapping technique, measuring void pore space and metrics gas permeability using the Gas Transport Model (GTM) helium gas injection method designed specifically for unconventional tight rocks, performing pyrolysis for quantitative organic matter, and measuring resistivity (Rw). Furthermore, a special focus will be on the characterization of organic matter and hydrocarbons. The results show that (1) newly acquired fresh shale samples undergo significant changes through evaporation and redistribution of liquids in the first weeks of freshness, and the rate of changing varies with time; (2) the mobility of hydrocarbons in different pores or of different viscosities can be determined by activation energy (Ea) which can be measured through NMR T1-T2 mapping at various sample temperatures; (3) combination of NMR T1-T2 mapping and the advanced programmed (multi-heating ramps, MHR) pyrolysis can verify whether light hydrocarbons reside in pores of different sizes or hydrocarbons of different viscosities in one type of pores. The resistivity measurement utilizes the cuttings samples from wells that have been drilled with Oil-Base Mud, in order to establish the Formation Brine Resistivity Rw for each horizon that cuttings correspond to. This technique can be applied on a foot by foot basis, and it had been cross checked for accuracy with different types of tests and data base.
Hui Xie (Schlumberger) Geometric effects need to be considered while interpreting logs acquired in high-angle (HA) and horizontal (HZ) wells. In our work, a multi-step, inversion-based workflow has been developed for analyzing logging-while-drilling (LWD) density and neutron measurements in HA and HZ wells. The workflow produces accurate layer properties (i.e., bulk density, photoelectric factor, and neutron porosity) by taking account of bed thickness, borehole effects, and tool response to boundary crossings and adjacent bed effects. Unlike conventional log-based petrophysical interpretation workflow, an initial layered earth model is constructed first using LWD borehole density images. An automatic boundary detection method is developed to extract the earth model from complex image features. After that, an inversion method is applied to adjust the geometry of the earth model and compute layer properties using nuclear measurements. In addition to the layered earth model, the interpretation model includes borehole geometry and mud properties along the wellbore trajectory. The inversion method relies on several nuclear fast forward models (FFMs). These FFMs are derived based on flux-derived sensitivity function maps obtained from Monte Carlo modeling, and they can provide accurate tool response modeling results for layered formation models with complex borehole environments. Gauss-Newton optimization with line search, adaptive regularization scheme, and parameter constraints is used in the inversion to minimize the weighted L2-norm error between the measured and forward modeled logs. The workflow has been validated using both synthetic and field data. The validation on synthetic data shows that true geometrical structure, layer formation density, PEF, and neutron porosity can be recovered within the accuracy of FFMs even in the formation beds where the layer thickness is thinner such that the measurements could not fully respond to the layer property. The tests on field data show that it is possible to determine a common geometrical model for density and neutron measurements, even though they have significantly different responses to the layering. Without our workflow, it would not possible to manually derive accurate layer properties due to the asymmetric nature of the neutron measurements and the common practice of attempting to compare the non-azimuthal neutron measurement with the azimuthal density measurements. The workflow provides an accurate method for quantitative petrophysical interpretations. In addition, the inversion results lead to a better understanding of multi-physics measurements in HA and HZ wells.
Edgar Velez (Schlumberger) From time to time when Borehole sonic measurements are discussed for high angle or horizontal wells, comments on the validity and use of the data arise. One of the most common misbeliefs is related to shear anisotropy; often there is a comment like: “anisotropy doesn’t work in high angle wells;” such comments are usually related to the most known application of the shear anisotropy that is to determine the maximum horizontal stress direction. The intended presentation will review the effect of well deviation with respect of the layers to sonic measurements such as compressional and dipole shear, is intended to include some basic waveform propagation physics and several examples of sonic log data quality control, processing and interpretation in deviated and high angle wells in different formations.
Nigel Clegg (Halliburton) Optimal well placement requires three-dimensional (3-D) spatial knowledge of the reservoir formation and fluids. Current one-dimensional (1-D) inversions of ultra-deep azimuthal resistivity logging-while-drilling(LWD) data recover formation boundaries above and below the wellbore, which are stitched together to form pseudo-2-D models (or “curtain plots”) along the wellbore. However, 1-D modeling, by definition, does not account for any lateral variations due to changes in formation dip, lithology, or fluid saturations, such that any actual 2-D or 3-D variations manifest ambiguously as artifacts or distortions in the pseudo-2D models. These lateral variations can have a significant impact on well placement and subsequent production-related decisions, such as where a change in well azimuth could be more beneficial than a change in inclination during drilling. An accurate and computationally efficient full 3-D inversion of ultra-deep azimuthal resistivity LWD data, capable of capturing arbitrary and multi-scale reservoir complexity, would yield 3-D earth models that could provide as-yet-unrealized insight for reservoir characterization and well placement. This paper presents the industry’s first such 3-D inversion of ultra-deep azimuthal resistivity LWD data. The case study describes a complex reservoir with significant sub-seismic faulting and a long history of water injection, resulting in significant fluid substitution within the reservoir formations. The complexities in this reservoir make it both an ideal candidate and a difficult, yet critical, first test to prove the value of 3-D inversion. In a well where major faults crossed the well path at an oblique angle, in a zone affected by complex water flooding, the resistivity boundaries indicated by 1-D inversions alone did not adequately explain the reservoir state. Analysis of density image data confirmed that the faults crossed by the well were both oblique (i.e. non-perpendicular to the well path) and tilted in the vertical plane. Several of these structures acted as a barrier to the migration of fluids and showed a sharp resistivity boundary from oil to water. This enabled mapping of the resistivity boundaries distant from the well path using ultra-deep resistivity LWD data. Combining the information from these tools with the four-dimensional (4-D) seismic data enabled validation of the 3-D inversion. The 1-D inversion yielded valuable information to assist in well placement, but the 3-D inversion provided significantly more insights, which will directly affect future reservoir-characterization and well-placement operations. It is very clear from the 3-D inversion that a tilted oil-water contact near the heel of the well results in horizontal, as well as vertical, changes in the fluid distribution, such that an azimuthal adjustment of the well path would have resulted in significantly greater reservoir exposure. Faults separating zones of water invasion, which crossed the well at an oblique angle, are clearly visible, indicating the position of the oil-water contact a significant lateral distance from the wellbore, which is vital information when determining how to complete the well and predict future production.
Farhan Alimahomed (Schlumberger) Objectives/Scope: Historically, vertical wells were used to correlate formation tops and determine the lateral continuity of the reservoir. With the advancements in horizontal drilling and logging, the industry is able to gather an immense amount of information about the rock as we drill farther away from the vertical section. Numerous industry publications indicate that approximately 40% of the perforation clusters do not contribute to production. Many factors play a role in such production behavior, but the most important factor is the breakdown of perforations and propagation of the hydraulic fractures through them. Several methods, such as limited entry design and placing perforations in similar type rock, have been applied to mitigate this problem; the information needed for these methods is obtained from logging the laterals or using drilling data to determine rock properties. Diagnostic tools such as production logs, permanent downhole fiber optics, radioactive tracers, and chemical tracers have been deployed to understand the varying production profiles seen across the unconventional reservoirs. Methods, Procedures, Process: This study focuses on three wells with lateral measurements to obtain petrophysical and geomechanical rock properties (one well in the Wolfcamp B and two wells in the Wolfcamp A). The wells also had pseudo rock properties calculated using surface drilling data. X-ray diffraction (XRD) and Rock Eval data is also available. In most instances, the perforation clusters in each stage were placed in good reservoir and completion quality rock with the aim to minimize the stress differential between clusters. Different perforation schemes were tested in each of the three wells — number of clusters and spacing, limited entry, and geometric design. The wellbore geosteering profile, whether in or out of zone, was also considered in relation to the subsurface structure. Results, Observations, Conclusions: Lateral measurements in all wells showed the changing lithology and rock types across the lateral. The Wolfcamp B had a production log that indicated twice as many clusters contributing in the section of engineered perforations compared to the section where the perforations were placed using gamma ray. Time-lapse chemical tracers in other wells indicated changing production profiles. For example, early on in the life of a Wolfcamp A well, the stages with clusters picked based on logs showed the highest production contribution compared to the geometric stages, but, later on, the trend started to shift in favor of the geometric clusters. The geometric stages were in an area of the wellbore where the carbonate content was highest. Novel/Additive Information: Comparisons of various data sets to production performance, such as the one included in this study, will provide some insight into the heterogeneous nature of the Wolfcamp shale and the impact of varying perforation techniques on production contribution from individual clusters.
Patricia Rodrigues (Whiting) The Niobrara Petroleum system in Colorado consists of several chalk and marl benches. The Niobrara B chalk is the main producing interval in Northeastern Colorado and which has been perforated by hundreds of horizontal wells. Vertical wells are not as abundant as horizontals, density of vertical wells varies per township, and only a few verticals have a modern suite of logs. Besides, the saturation of the Niobrara B chalk shows important areal changes as it is linked to the heat anomaly of the Colorado mineral belt. Acknowledging the need for a better understanding of the reservoir, we decided to obtain triple-combo horizontal logs in each new pad drilled. This work explains the workflow we followed to utilize the dense amount of information provided by horizontal logs to improve both the mapping of the water saturation in the Niobrara B chalk and the delineation of the field. Incorporating horizontal logs in reservoir characterization of the Niobrara B chalk presented three unique challenges: 1) different rock volume sampling between vertical and horizontals, 2) mixed intervals due to well navigating across different zones, and 3) limitations of mapping software to incorporate information from horizontal wells. The following workflow was used to overcome these challenges:
The incorporation of horizontal data in the mapping of the water saturation of the Niobrara B, allowed a better delineation of the edges of the field and adjustment of the corresponding inventory; it also showed that some of the faults are associated with changes in saturation. Each new log drilled was quickly evaluated and incorporated into the map for quick decision making regarding new drilling and completions.
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