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We present methodology to evaluate long term sequestration viability of CO2 reservoirs using drill cuttings.
Cuttings volatile data was obtained from 2 parallel horizontal wells, drilled along the same vertical trajectories, separated by 400 meters in 2019. One horizontal well drilled within 100 meters of a 1994 vertical oil well. The already produced section shows very low CO2 compared to the rest of this lateral and the entire length of the twin lateral. Oil production from the 1994 vertical well reduced reservoir pressure, caused CO2 loss from formation water, and produced CO2 to the surface, lowering reservoir CO2 contents. This example shows cuttings volatiles analyses can detect past CO2 reservoir loss, and is a valuable tool for evaluating long term storage viability of CO2 reservoirs.
Another horizontal well, different location and formation, produced about one third of the expected oil. Cuttings volatiles indicate that the heel third of the lateral was oil productive, but that oil in the two thirds of the lateral towards the toe had been lost along a major fault. The CO2 contents in the oil pay zone are normal, but in the oil depleted zone CO2 is very low. Loss of oil from the reservoir along the fault reduced reservoir pressure, resulting in dissolved CO2 loss from formation waters, and CO2 loss along the fault.
Cuttings from ten wells from the same limestone formation in a two county area in Oklahoma were analyzed. Nine of the wells show normal CO2 contents. The tenth well drilled across a major fault has 10 to 100 times less CO2 than the other 9 laterals. CO2 in interstitial waters was lost from the reservoir via the fault. Rock Volatiles data indicate the zone drilled by this well is not adequate for long term CO2 sequestration.
A two mile high temperature gas horizontal well was analyzed crosses a major fault near the toe. Very high CO2 contents are observed at the fault. The CO2 is generated in a deeper formation and is migrating out through the penetrated formation. Neither formation is adequate for long term CO2 sequestration.
Cuttings from two CCS wells drilled by the Kansas Geological Survey were analyzed for cuttings volatiles CCS reservoir viability assessment. Both wells show no signs of CO2 depletion, and are considered by us to be low risk for long term CO2 loss.
Rock Volatiles CO2 analyses of cuttings and core is a powerful tool for assessing long term CO2 sequestration viability before new wells are drilled.
Welker, Carrie (Schlumberger Reservoir Laboratories) | Feiner, Sarah (Schlumberger Reservoir Laboratories) | Lishansky, Rachel (Schlumberger Reservoir Laboratories) | Phiukhao, Wipawon (Schlumberger Reservoir Laboratories) | Chao, Jiun-Chi (Schlumberger Reservoir Laboratories) | Moore, Russell (Schlumberger Reservoir Laboratories) | Hall, Don (Schlumberger Reservoir Laboratories)
Abstract Archived cuttings samples (n = 6713) from 58 wells located in the SCOOP and STACK plays of the Anadarko Basin in Oklahoma (Figure 1; Table 1) were analyzed for their bulk trapped fluid content (fluid inclusions and other tightly held volatiles) via the fluid inclusion stratigraphy (FIS) technique. Fluid inclusion petrography (n = 300) and microthermometry (n = 58) analyses were also performed on selected intervals, based on FIS results. Data were used to evaluate the vertical and lateral distribution of hydrocarbons and non-hydrocarbon volatiles, oil gravities, phase state, salinity, and burial temperatures. The most prominent gas and liquid hydrocarbon FIS responses are recorded in the Caney to Viola sections. Both migrated and locally generated components are distinguished, and several episodes of migration may be documented within a given well. Overall, FIS oil/condensate responses and petrographic observations suggest a liquids-enhanced interval at 8,000–12,000 ft, although in some instances liquid petroleum zones extend to 15,000 ft. Gas-enrichment occurs to the west in response to increased thermal maturity, and sulfur species related to thermochemical sulfate reduction at high temperature occur towards the west and at depths >13,000 ft. Measured petroleum inclusions show mostly values of 38° to 45° API gravity. Most petroleum inclusions homogenize via bubble-point transition, and bubble-point temperatures suggest that they occur as undersaturated liquids at current reservoir conditions. Aqueous inclusion homogenization temperatures (Th) imply maximum burial temperatures that are generally higher than current temperatures, and probably reflect 3000–4000 ft of uplift since inclusion formation. Inclusion salinities are generally in the 1–5 weight percent NaCl-equivalent range suggesting brackish to evolved basin fluids. Independent measures of thermal maturity, including pyrolysis, Th of aqueous inclusions, and biomarkers, are in general agreement, and suggest that much of the recorded petroleum was proximally sourced. This historically productive region is attractive for unconventional reservoir development due to liquids potential and favorable economics. However, fluid characteristics can vary greatly over a relatively small area, resulting in significant differences in recovery from nearby wells. By analyzing fluid inclusions, it is possible to establish regional hydrocarbon potential with a small amount of unpreserved, archived drill cuttings and evaluate the likely production characteristics of fluids within a given area.
Abstract 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 compartmentalization. The data collected from this effort profoundly improved the ability to geosteer in the best target consistently and was immediately relevant and incorporated into completion design. Geochemical signatures for subseismic faults and fractures were also detected, along with clear identification of stratigraphic location of the borehole. Mass spectrometry (MS), combined with collected thermal maturity data helped advance petroleum system mapping and understand well performance. These methods were found to be lower risk and more cost effective to run than horizontal wireline logs, while providing 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 MS 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 yielded a surprising fault and fracture indicator that also became useful to completion design 4.) MS 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.
Abstract Present-day fluid type and contacts in carbonate reservoirs can be difficult to determine from standard formation evaluation techniques because of complex rock properties and variable fluid compositions. In such situations, integrating novel rock-based geochemical analyses of adsorbed and inclusion-trapped fluids helps reduce fluid contact uncertainty and evaluate the probability of various fluid types. The rock-based analyses include three techniques that can be applied to either core or cuttings samples. First, volatile compounds adsorbed or trapped in pore spaces are measured by mass spectrometry using a patented pumpdown volatiles (PDV) technique. Second, fluid inclusion volatiles (FIV) analysis also uses mass spectrometry to characterize volatile compounds released from fluid inclusions when samples are crushed. Both analyses are rapid and inexpensive and therefore are frequently applied to entire wells to allow stratigraphic correlation of responses for mapping fluid types and contacts. However, because FIV signatures include both present and paleo fluids, additional analyses are needed when filling history is complicated (e.g., gas displaces oil). For example, PDV and FIV interpretations can be confirmed and refined with a third technique, thermal desorption gas chromatography/mass spectrometry, Iatroscan, and/or Rock Eval pyrolysis. In addition to these analytical techniques, a statistical modeling tool has been developed for quantitative probability predictions of reservoir fluid type from complex FIV and petrophysical signatures. The model is constructed by calibrating FIV and petrophysical data to known test results, and then applying it to predict fluid type in wells where test results are absent or ambiguous. Besides providing an integrated approach to fluid type and contact evaluation, this tool allows multiple scenarios and quantification of uncertainty. This paper summarizes methodologies and key applications of rock-based techniques for accurate resource evaluation, improved completion decisions, and optimized exploration, development, and production strategies in carbonate reservoirs. Introduction Using traditional well logs or seismic to identify present-day fluid type and contacts (FT&C) in carbonate reservoirs can be challenging due to complex and heterogeneous reservoir lithology and properties, aqueous pore fluid composition, and low-resolution seismic data. In petroleum reservoirs, rocks may adsorb small quantities of the surrounding fluid medium or the fluids may be trapped within mineral cements in the form of fluid inclusions. These fluids are often detectable using techniques based on mass spectrometry, including analyses of ExxonMobil patented pumpdown volatiles (PDV) (1) and fluid inclusion volatiles (FIV) (2), often combined with thermal desorption gas chromatography/mass spectrometry (TD-GC/MS). These rock-based techniqes can be used to identify FT&C and are most successful using closely spaced conventional or sidewall core samples, but cuttings have also been used successfully. The techniques are not applicable for samples drilled with oil-based mud and some drilling additives in water-based mud systems may also complicate interpretations. The data are typically interpreted qualitatively based on the chemical results concerning the location of hydrocarbon migration pathways, seals, and fluid type. However, statistical analysis and modeling can be used to give quantitative probabilities of fluid type (e.g., gas or oil) by calibrating geochemical responses against known test results and applying to other wells where test results were absent or ambiguous. In this paper, we summarize these methodologies and show examples of how we integrate these rock-based techniques with petrophysical evaluation and statistical approaches to determine FT&C. The results reduce uncertainty regarding the hydrocarbon phases and fluid contacts present in the carbonate reservoirs.
Feiner, Sarah (Schlumberger) | Lishansky, Rachel (Schlumberger) | Phiukhao, Wipawon (Schlumberger) | Chao, Jiun-Chi (Schlumberger) | Moore, Russell (Schlumberger) | Hall, Don (Schlumberger) | Kubacki, Carrie (Malin Space Science Systems)
Abstract Bulk trapped fluid content data acquired from fluid inclusion analysis of more than 7,000 cutting samples from 26 wells onshore Canning Basin, Australia (Figure 1; Table 1), provide insight into the hydrocarbon potential of this largely unexplored basin. Although key unconventional targets are thought to reside within the Ordovician section, exploration risks include the thickness, distribution, and presence of producible reservoir; source distribution and maturity; and the ability to stimulate reservoirs. Samples examined in this study range in age from Cretaceous to Ordovician (Figure 2). The overall analysis of samples employed X-ray fluorescence (XRF) to determine inorganic elemental composition. Fluid inclusion petrography and microthermometry analyses were performed on intervals selected on the basis of initial bulk fluid inclusion analysis results. The resulting data allowed evaluation of the vertical and lateral distribution of hydrocarbons and nonhydrocarbon volatiles, oil gravity values, phase state, salinity, and burial temperature. Homogenization temperatures above current reservoir temperatures are present in many of the petroleum and aqueous fluid inclusions, suggesting that fluids dropped through bubblepoint during uplift of 1000–1800 m and current reservoir fluids are likely dual-phase. Maturity values calculated from fluid inclusion data generally range from 0.6 to 1.3% vitrinite-equivalent. Regional variability in maturity within potential source intervals leads to variable fluid composition, with estimates that API oil gravity values (based on fluid inclusions) can range from 28 to 45°, although most measured values range from 37 to 44° API gravity. Data indicate source rock potential in the Upper Ordovician Bongabinni Formation of the Carribuddy Group, Upper Ordovician Nita Formation, Middle Ordovician Goldwyer and Willara Formations, and the Lower Ordovician Nambeet Formation. Lateral and vertical distribution is not uniform within these units, and the prospectivity of the Ordovician Nita-to-Nambeet section is verified. Several formations within the Canning Basin exhibit potential for conventional exploration, including: Middle Jurassic Wallal Sandstone, Lower Permian Grant Group Sandstones, Devonian Tandalgoo Sandstone, Upper Ordovician Nita Formation, Middle Ordovician Willara Formation and Lower Ordovician Nambeet Formation. The study identified the presence of migrated and locally generated fluids, including a deep-sourced mature gas phase that appears to have invaded portions of the basin. The occurrence of shallow bacterial microseeps suggests associated deeper accumulations are present. It is anticipated that accumulations will be classified as combined conventional and unconventional reservoirs. The study identified multiple, individual targets, which vary geographically, indicating the need for a directed approach to optimize drilling and completion.