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Abstract Legacy crushed rock analysis, as applied to unconventional formations, has shown great success in evaluating total porosity and water saturation over the previous three decades. The procedure of crushing rock into small particles improves the efficiency of fluid recovery and grain volume measurements in a laboratory environment. However, a caveat to crushed rock analysis is that water and volatile hydrocarbon evaporate from the rock during the preparatory crushing process, causing significant uncertainty in water saturation assessment. A modified crushed rock analysis incorporates nuclear magnetic resonance (NMR) measurements before and after the crushing process to quantify the volume of fluid loss. The advancements improve the overall total saturation quantification. However, challenges remain in the quantification of partitioned water and hydrocarbon loss currently derived from NMR spectrum along with its uncertainty. Furthermore, pressure decay permeability from crushed rock analysis has been reported to have two to three orders of magnitude difference between different labs. The calculated pressure decay permeability of the same rock could even vary several orders of magnitude difference with different crushed size, which questions the quality of the crushed pressure decay permeability. In this paper, we introduce an intact rock analysis workflow on unconventional cores for improved assessment of water saturation and enhanced quantification of fast pressure decay matrix permeability from intact rock. The workflow starts with acquisition of NMR T2 and bulk density measurements on the as-received state intact rock. Instead of crushing the rock, the intact rock is directly transferred to a retort chamber and heated to 300 °C for thermal extraction. The volumes of thermally-recovered fluids are quantified through an image-based process. The grain volume measurement and a second NMR T2 measurement are performed on post retort intact rock. The pressure decay curve during grain volume measurement is then used for calculating pressure decay matrix permeability. Total porosity is calculated using bulk volume and grain volume of the rock. Water saturation is quantified using total volume of recovered water. In addition, the twin as-received state rocks are processed through the crushed rock analysis workflow for an apple-to-apple comparison. Meanwhile, pressure decay permeability is cross-validated against the steady state permeability of the same sample. The introduced workflow has been successfully tested on different formations, including Bakken, Bone Spring, Eagle Ford, Cotton Valley, and Niobrara. The results show that total porosities calculated from intact rock analysis are consistent with total porosities from crushed rock analysis, while water saturations from the new workflow are average 8%SU (0.2–0.7%PU of bulk volume water) higher than those from the prior crushed rock workflow. The study also indicated that for some formations (e.g., Bone Spring) the fluid loss during crushing process is dominated by water, however, for some other formations (e.g., Bakken), hydrocarbon loss is significant. Pressure decay permeability quantified using intact rock analysis is also confirmed within an order of magnitude of steady state matrix permeability.
Steiner, S.. (ADCO) | Raina, I.. (Schlumberger) | Dasgupta, S.. (Schlumberger) | Lewis, R.. (Schlumberger) | Monson, E. R. (ADCO) | Abu-Snaineh, B. A. (ADCO) | Alharthi, A.. (ADCO) | Lis, G. P. (Schlumberger) | Chertova, A.. (Schlumberger)
Abstract ADCO started its unconventional exploration campaign in 2012 targeting the tight carbonate sequences known as Wasia Group, onshore Abu Dhabi. A front-end loaded data gathering strategy was employed to acquire extensive latest generation logging data tailored for unconventional reservoirs. In a number of wells the entire reservoir section was cored, often up to 800 ft per well, leading to more than 3000 ft of core retrieved to date. ADCO applied unconventional core analysis technologies, such as retort analysis, to generate the optimal core results. Key parameters such as effective porosity, pore size distribution, TOC, source rock maturity, mineral compositions and fluid saturations were determined from logs and core data (where available). This paper will focus on the petrophysical challenges during the evaluation of the Wasia Group. We will demonstrate that conventional core analysis techniques have only limited applicability, whereas core analysis techniques designed specifically for unconventionals provide more relevant results. A log analysis methodology centered on the application and importance of NMR in unconventional liquid plays is presented. Porosity data measured through retort analysis provide an excellent fit to NMR log-based porosity measurements. Conventional core analysis results generated a poor fit to log porosity, and the resulting values exhibited scatter with a large standard deviation. T2 distribution from NMR log data suggests the presence of large pores with good fluid mobility, which requires confirmation through formation testing or production. Log data-derived rock typing was performed. It is based on principal component analysis of the reservoir section. Rock classification may help in selecting suitable zones for hydraulic fracture initiation. Lessons learned from the initial wells for core recovery and analysis techniques are summarized below and have been implemented in later wells: –Preserve part of the core for robust saturation measurements. –Stop acquisition of conventional poro-perm data –Focus on unconventional-specific retort-based techniques for core petrophysics –Focus on pulse decay permeabilities –Use scratch test to aid in core analysis sample selection process, especially for rock mechanics –Add core T1/T2 NMR and MICP to future core analysis programs The complete integration of core and log data has allowed for a thorough assessment of the unconventional hydrocarbon potential within the ADCO concession.
Durand, Melanie (Shell Exploration and Production Company) | Nikitin, Anton (Shell International Exploration and Production) | McMullen, Adam (Shell Exploration and Production Company) | Blount, Aidan (Shell Exploration and Production Company) | Driskill, Brian (Shell Exploration and Production Company) | Hows, Amie (Shell International Exploration and Production)
ABSTRACT As activity increases in the Permian Basin and multiple billion-dollar acquisitions at upwards of &50,000/acre continue, there is a strong incentive for E&P operators to optimize the development in their existing acreage. Unfortunately, maximizing oil production typically results in significant amounts of produced water. Water cuts for individual Permian wells commonly range from 50 to 90% of total liquid production, thus the ability to predict water to oil ratio (WOR) of the produced fluids has a major importance for development planning (Scanlon et al., 2017). Petrophysicists are responsible for fluid saturation modeling, which provides the basis for predicting WOR. Core data acquisition and analysis are critical for developing a quantitative petrophysical model. However, accurately measuring saturations of cores taken from unconventional reservoirs continues to pose significant challenges originating from uncertainties in the acquired data, assumptions used to interpret these data and more broadly, due to increased relative uncertainty associated with tight, low-porosity formations. For example, the crushing of the core samples, which is required for efficient fluid extraction in tight rocks, causes systematic fluid losses which are not typically quantified. Instead, all as-received air-filled porosity is commonly assumed to represent hydrocarbons that have escaped during coring due to gas expansion. Additionally, fluid extraction from commercially available retorting systems can have widely variable fluid collection efficiency (<100%) resulting in significant inconsistencies between the weight of the collected fluids and sample weight loss during retorting experiments. The Dean-Stark technique removes not only fluids (water and oil) but an unknown volume of the extractable organic matter, and it only allows for direct quantification of the volume of extracted water. The reconciliation of fluid volume as well as fluid and sample weight data delivered by either of the two techniques (i.e., retorting or Dean-Stark) requires numerous assumptions about pore fluid properties which are typically not verified through direct measurements. We demonstrate that such assumptions can lead to up to 50% uncertainty in water saturation estimates. To address such critical uncertainties, a new core analysis workflow using improved core characterization and fluid extraction techniques was developed. To address fluid loss during crushing, this workflow employs advanced NMR measurements performed on both as-received and crushed samples to quantify fluid losses. Also, this approach uses retorting techniques with close to 100% fluid collection efficiency specially developed for core sample characterization. The workflow is further optimized to avoid fluid loss during sample handling and includes repeated grain density and geochemical measurements at different stages. As a result, the new workflow addresses uncertainties in acquired data and better informs the assumptions for interpreting the measured data into the desired petrophysical properties (e.g. total porosity, water saturation). The workflow is demonstrated for a set of Wolfcamp samples.
Nikitin, Anton (Shell International Exploration and Production) | Durand, Melanie (Shell Exploration and Production) | McMullen, Adam (Shell Exploration and Production) | Blount, Aidan (Shell Exploration and Production) | Driskill, Brian (Shell Exploration and Production) | Hows, Amie (Shell International Exploration and Production)
Sustained E&P activity levels and slim margins on highly valued Permian Basin acreage drive operators to leverage information as much as possible and in ways not seen in the recent past. Data accuracy, especially in this fast-paced, competitive environment, is strongly desired. Core analyses provide subsurface static calibration, but the thick stratigraphic section comprised largely of sublog scale facies, challenges a cost-effective approach to collect sufficient calibration data.
Saturation determination is a key petrophysical deliverable that has multiple uses, including landing zone assessment. Calibration of saturation models may originate in several ways: proprietary or joint venture core, industry consortia databases, data trades with other operators, government databases, or publications. Internal and external reviews of subsurface model inputs have repeatedly shown that Permian Basin saturations, in particular, have a wide distribution and large uncertainty. Accurately measuring core fluid saturations in tight rock continues to pose significant challenges originating from the currently accepted laboratory methods, assumptions used to interpret those data and more broadly, due to increased relative uncertainty associated with tight, low-porosity formations.
For example, crushing core samples, which enhances fluid extraction in tight rocks, causes systematic fluid losses in the case of core samples of liquid-rich mudstone formations, which are not typically quantified. Instead, as-received air-filled porosity is commonly assumed to represent hydrocarbons that were forced from core during acquisition/retrieval due to gas expansion. Additionally, fluid extraction from commercially available retorting systems have widely variable fluid collection efficiencies (<100%) resulting in significant inconsistencies between the weight of collected fluids and sample weight loss during retorting experiments. The Dean-Stark technique removes not only water and oil, but an unknown volume of solvent-extractable organic matter, and it only allows for direct quantification of the extracted water volume. Finally, fluid and solid losses during handling in the laboratory are unassessed in current commercial laboratory procedures. The reconciliation of fluid volumes with fluid and sample-weight data delivered by either of the two techniques, i.e., retort or Dean-Stark, requires numerous assumptions about pore fluid properties, which are typically not verified through direct measurements. We demonstrate that such assumptions can lead to extreme uncertainty in estimates of water saturation.
To address such critical uncertainties, a new retort-based core analysis workflow using improved core characterization and fluid-extraction techniques was developed. In one advancement, this workflow employs NMR measurements systematically performed on all as-received and crushed samples to quantify fluid losses during crushing. This approach also uses a specially developed fluid collection apparatus with close to 100% fluid collection efficiency. In addition to these advances in measurements, the workflow is optimized to avoid fluid losses during sample handling and includes repeated grain density and geochemical measurements at different stages for quality control (QC). As a result, the new workflow reduces the uncertainties in acquired data and better addresses the assumptions, i.e., parameter corrections for fluid losses, in interpreting measured data into core total porosity and core fluid saturations. The workflow is demonstrated for a set of Delaware Basin Wolfcamp A formation samples and the results suggest that previous crushed-rock core analysis protocols underestimate water saturation by at least 30% or ~15 saturation units (s.u.) for this liquid-rich mudstone formation.
Blount, Aidan (Shell Exploration and Production Company) | Croft, Tyler (Shell Exploration and Production Company) | Driskill, Brian (Shell Exploration and Production Company) | Tepper, Brian (Shell Exploration and Production Company)
In today’s competitive cost environment, core acquisition and analysis is too often dismissed as unaffordable. This forces petrophysicists to make every dollar count in core evaluation. Tough choices have to be made—many people chase the lowest bid, least expensive methodologies, reduced oversight, and less sampling. In this paper, insights will be shared from a comprehensive round-robin study directly comparing the results of the most common techniques (GRI/Retort/RCA) used by major vendors. Understanding differences in techniques early in an evaluation process can help efficiently direct technical spending.
As with many comparison studies, this project started with the reconciliation of analysis sourced from different laboratories using different methodologies.
There was a significant business driver to this work as we noticed differences in measured porosity and fluid saturations that contribute to significant differences, approximately 25%, in hydrocarbon pore volume among vendors using alternative techniques. These differences directly impact log calibration objectives as well as estimations of hydrocarbons in place.
We began to ask a series of simple questions: Should we use crushed samples or routine core plugs? What is the impact of analytical technique on the results? What role does lithology and organic content play in the results from different analytical techniques? What is the role of sample size? What is the variability between vendors for identical procedures? If there is variability, what is the apparent cause?
A set of 10 twin samples of Permian Bone Spring formation from the Delaware Basin in Texas and New Mexico was evaluated using a variety of laboratory-derived measurements, including X-ray diffraction (XRD), total organic carbon (TOC)/RockEval, retort, and Dean- Stark/Gas Research Institute (GRI) protocol analyses from two labs and RCA from one lab. These 10 samples were selected to represent varying lithofacies with a range of organic, mineralogical, and water/oil content. The level of oversight at each data source was also tracked.
Through detailed analysis of the raw data from these measurements, we address the questions above. With these results, we hope to (1) maximize every dollar spent in core analysis, (2) focus oversight where it is truly required, and (3) accurately and consistently evaluate the core analysis in the Permian play for fast and value-driven business decisions.