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Smith, Christopher (Advanced Hydrocarbon Stratigraphy) | Pool, Susan (West Virginia Geological and Economic Survey) | Dinterman, Philip (West Virginia Geological and Economic Survey) | Moore, Jessica (West Virginia Geological and Economic Survey) | Vance, Timothy (West Virginia Geological and Economic Survey) | Smith, Timothy (Advanced Hydrocarbon Stratigraphy) | Gordon, Patrick (Advanced Hydrocarbon Stratigraphy) | Smith, Michael (Advanced Hydrocarbon Stratigraphy)
Abstract The distribution of liquid hydrocarbon (HC) resources in the Marcellus Formation throughout West Virginia (WV) is a matter of economic importance for the State of West Virginia and Marcellus operators. Herein, the West Virginia Geological and Economic Survey (WVGES) and Advanced Hydrocarbon Stratigraphy (AHS) have undertaken a project to map the composition and quantities of liquid gasoline range HCs present in drilling cuttings from counties in and neighboring the WV liquids fairway using Rock Volatiles Stratigraphy (RVStrat). Cuttings were analyzed from 12 wells, including air drilled wells, from Doddridge, Marshall, Ritchie, Tyler, Harrison, and Wetzel counties; spud dates range from 1953-2013. Insights into the geographical distribution of liquids quantities and compositions and the regional petroleum system were gained with a focus on the Devonian-aged shales, i.e. the upper and lower Marcellus Formation and the West River and Geneseo shale members of the Genesee Formation. Major results were identification of apparent thermal maturity trends embedded in the liquids composition across the basin where there is a trend of increasing paraffin (alkane) and decreasing naphthene (cycloalkane) content as a function of depth. A trend of decreasing size (number of carbon atoms) of the liquid molecules vs depth was observed in the West River, Geneseo, and upper Marcellus indicative of thermal maturity. The liquids distribution across the Marcellus fits within expectations from production data showing a trend of increasing content moving westward from northcentral WV towards the Ohio River; liquid saturations measured were likely ≤1% of the original subsurface saturation. The liquids content in the Marcellus shows an apparent declining exponential vs depth trend likely linked to the progression of catagenesis. An anomalous well that may have undergone a significant gas migration/expulsion event, resulting in less liquid content and a preferential depletion of the more volatile liquid HC species was identified. There is also a trend of increasing mechanical strength of the cuttings vs depth likely due to compaction; there are differences in mechanical strength as function of when the well was drilled, before or after 2009 (likely due to PDC [polycrystalline diamond compact drill bits); this was the only bias identified due to the age of the sample or mud system used. The value of being able to collect usable and meaningful geochemical data from air drilled wells where the cuttings are several decades old with minimal cuttings material by RVStrat should not be understated; it allows using samples that are typically considered unsuitable and offers unique opportunities for petroleum system assessments.
Abstract We introduce a physics-based method for explicit pore pressure prediction in naturally fractured shale petroleum reservoirs. Failing to account for the actual cause of overpressure leads to underestimation of the pore pressure at depth. This is particularly important in shales that have not reached pressure equilibrium yet due to fluid expansion caused by currently active or recent-in-geologic-time hydrocarbon generation. Published geological studies indicate that the main overpressure mechanism in the Rocky Mountain Region is the active generation of hydrocarbons. We corroborate this hypothesis with a physics-based formulation built upon the Biot principle of effective stress. The key aspect of the new methodology is the determination of the in-situ Biot coefficient using well logs and formation pressure tests. Effective stress is computed as a function of sonic porosity from rigorous equations. The computed effective stress is subtracted from the overburden stress, and the difference is then divided by the Biot coefficient to determine the pore pressure. The overburden stress is calculated from density logs. The workflow is tested with well logs and real Drill-Stem Test (DST) data from the Powder River Basin of northeastern Wyoming. Pressure data points from the Frontier tight sandstone reservoir of the Niobrara and Mowry total petroleum systems are plotted in a sonic velocity vs. effective stress graph. These measurements fall outside a normal loading curve and track a faster trend. This is an indication of abnormally high pressures driven by active hydrocarbon generation in the Powder River Basin. Most of the traditional pore pressure prediction models use empirical parameters and implicitly assume undercompaction as the primary cause of overpressure. Furthermore, the models that follow an effective stress approach assume a Biot coefficient equal to unity. This study demonstrates that hydrocarbon generation as an overpressuring mechanism in shales can lead to Biot coefficients larger than unity. The accurate estimation of pore pressure has important implications in the safe and successful development of unconventional reservoirs. The majority of the available pore pressure estimation models rely on empirical parameters extracted from statistical analysis and best-fit exercises. While these models have proven useful, the empirical parameters they use are case-dependent and difficult to determine in areas with little or none regional experience. The new pore pressure model, in contrast, 1) follows a physics-based approach and does not rely on the use of fitting parameters, and 2) manages more efficiently well logs and pressure data because this information is combined and used for calibrating a quantity with physical and geomechanical significance (the in-situ Biot coefficient), rather than for calibrating an empirical parameter.
Jones, Peter (Devon Energy) | Dressler, Drew (Devon Energy) | Conner, Tyler (Devon Energy) | O'Brien, Josh (Devon Energy) | Klaassen, Trevor (Devon Energy (former)) | Bingham, Sean (Auburn University)
Abstract Objectives/Scope: Increasing focus has been directed towards value that can be derived from the analysis of produced water from unconventional wells. Work by Laughland et al. (2014), Wright et al. (2019) and Jweda et al. (2020) have shown that formation water from different zones can be recognized and distinguished from stimulation water. Although time-lapse geochemistry (TLG) studies may be designed for individual wells or lease development projects, companies typically have an abundance of water chemistry data that was obtained for various production-related issues. Devon is leveraging this data to provide value to geoscientists in active exploration and development areas. The historical data serve as a framework for supporting detailed TLG studies, as well as a resource that can be quickly drawn upon to assess a variety of operational issues. Through development of a Genetic Origin and Alteration Tool (GOAT), the identification of formation water from different horizons is enhanced. Additionally, GOAT provides an innovative application for unmixing produced waters from multiple contributing zones. The workflow assists in assessment of the stimulated rock volume (SRV) and changes in the communicating rock volume (CRV) over time. This is critical to understanding drainage behavior and vertical connectivity between multiple zones with stacked-well development patterns. Methods/Procedures/Processes: Produced water chemistry is influenced by factors including: the composition of the original water at time of deposition, proximity to salt and anhydrite, rock-water reactions relating to mineral diagenesis, depth/temperature, and fluid migration. Thus, the characteristics of formation water in adjacent horizons can vary greatly due to differences in the diagenetic pathway for each zone. The GOAT interpretive scheme uses a radar-plot with axes composed of ratios that highlight the common changes accompanying water diagenesis. Differences in shapes are used to quickly group water types and origin. The GOAT facilitates the processing of many samples, so that end-member components may be recognized for use in solving unmixing problems. Analytical methods used included standard water chemistry analysis with extended metal ions and isotopic geochemistry (δ18O and δD).
Abstract Geochemical data measured on petroleum samples sequentially extracted from Avalon Shale and Upper Wolfcamp (UW) core samples using several solvents and from oil samples collected at five wells completed in the UW reservoir were used to estimate the amount of producible oil, non-producible sorbed petroleum, and immobile bitumen in those core samples. UW core samples that have reached the middle to late oil window at two locations were sequentially extracted using a weak solvent (cyclohexane; CH), a stronger solvent (toluene), and a very strong solvent (chloroform-methanol; CM). Similar kinds of geo-chemical data were measured on the core extracts (after heating them to evaporate the solvents), and on native and topped oil samples. CH extracts obtained from UW mudrock cores that contain oil-prone kerogen or oil+gas-prone kerogen exhibit n-alkane profiles characteristic of producible oil, but extracts obtained from them using stronger solvent do not resemble oil – indicating most of the producible oil in the core samples was extracted by CH, while stronger solvents principally extracted bitumen: i.e., more polar compounds. CH also extracted oil that migrated into two UW siltstone cores that contain only a small amount of gas-prone kerogen. Likewise, the abundance of SARA compounds and CHONS in the topped oil samples is more similar to the composition of CH extracts than extracts obtained using toluene and CM (which contain significantly more resins and asphaltenes). But moderate differences in the composition of CH extracts and topped oil samples demonstrate that CH extracted resin-rich non-producible sorbed petroleum as well as producible oil. Modeling results that were used to constrain the range of the amount of sorbed petroleum in CH extracts and the composition of that component support the idea that those extracts contain a significant amount of non-producible sorbed petroleum enriched in resins. In addition, estimates of the amount of different kinds of petroleum in UW 1 and UW 2 SR samples utilizing geochemical data agree remarkably well with similar estimates made using results of a modified CRA procedure that involves sequentially extracting core samples with CH and toluene. Because SR samples contain a significant amount of sorbed petroleum that is extracted by the solvents used during CRA analyses, those results overestimate the saturation of producible oil in core samples. This conclusion indicates the fraction of the producible oil present in SR reservoirs that is recovered is higher than is commonly assumed.
Johnson, Andrew C. (Schlumberger) | Miles, Jeffrey (Schlumberger) | Mosse, Laurent (Schlumberger) | Laronga, Robert (Schlumberger) | Lujan, Violeta (Schlumberger) | Aryal, Niranjan (Schlumberger) | Nwosu, Dozie (Schlumberger)
Abstract Formation water saturation is a critical target property for any comprehensive well log analysis program. Most techniques for computing saturation depend heavily on an analyst’s ability to accurately model resistivity measurements for the effects of formation water resistivity and rock texture. However, the pre-requisite knowledge of formation water properties, particularly salinity, is often either unknown, varying with depth or lateral extent, or is difficult to derive from traditional methods. A high degree of variability may be present due to fluid migration from production, water injection, or various geological mechanisms. In unconventional reservoirs, the complexity of the rocks and pore structure further complicates traditional interpretation of the available well logs. These factors introduce significant uncertainties in the computed fluid saturations and therefore can substantially affect final reserves estimates. A novel technique in geochemical spectroscopy has recently been introduced to distinguish the chlorine signals of the formation and borehole. The new, quantitative measurement of formation chlorine enables a direct calculation of bulk water volume for a given formation water salinity. When integrated into a multi-physics log analysis workflow, the chlorine-derived water volume can provide critical information on fluid saturations, hydrocarbon-in-place, and producibility indicators. This additional information is especially useful for characterizing challenging and complex unconventional reservoirs. We present the new technique through several full petrophysical evaluation case studies in organic shale formations across the U.S., including the Midland, Delaware, Marcellus, and DJ basins. We solve for formation-specific water salinity and bulk water volume through an optimization that combines chlorine concentration with resistivity and dielectric measurements. These outputs are integrated into comprehensive petrophysical evaluations, leveraging a suite of advanced well log measurements to compute final fluid and rock properties and volumetrics. The evaluations include geochemical mineralogy logs, 2D NMR analyses, dielectric dispersion analyses, basic log measurements, and multi-mineral models. The results underscore the utility of the new spectroscopy chlorine log to reduce petrophysical model uncertainties in an integrated workflow. While this workflow has been demonstrated here in several U.S. organic shale case studies, the fundamental challenges it addresses will make it a valuable solution for a range of unconventional reservoirs globally.
Abstract Cuttings are an undervalued resource that contain vast amounts of relevant formation evaluation (FE) data in the form of entrained volatile chemistries from present day formation liquids/gases. Analysis of these chemistries in cuttings, or other materials (core, side wall core, and muds), enables decisions from well level completions to acreage/basin assessments on an operational timescale. This work compares analysis of rock volatiles to traditional FE (water saturation and permeability) data to demonstrate correlations to field studies in the Delaware Basin and the STACK. The field study from the SCOOP demonstrates how the analysis can be used to drive completion decisions; studies from the STACK demonstrate how the analysis drove acreage assessment and utilization decisions. All cases are presented from nonhermetically sealed samples showing the applicability of the analysis to fresh or legacy materials. A unique cryo trap-mass spectrometry (CT-MS) system has been developed by Dr. Michael Smith enabling the gentle extraction of volatiles from cuttings, or other materials, and the subsequent identification and quantification of the extracted chemicals. All possible chemistries (hydrocarbons, organic acids, inorganic acids, noble gases, water, etc.) are extracted by gentle volatilization at room temperature under vacuum conditions and concentrated on a CT; the chemistries are separated by warming the CT and volatilizing as a function of sublimation point and then analyzed by MS. Advantages of this CT-MS over GC-MS are that chemicals that would not survive the conditions of a heated GC system can be analyzed and that the analysis does not require different columns as a function of the species type analyzed. The analysis works on both water and oil based mud systems. These results are combined with a geological interpretation to enable application. The comparison field studies show that the analysis successfully reproduced Sw and permeability trends from petrophysics and sidewall core analysis. The SCOOP field study identifies the mechanism of underproduction in a Hoxbar well and a simple completion strategy for the lateral that would have significantly reduced costs while enabling equivalent production. The STACK field study was utilized by an operator to evaluate and understand the petroleum system across their acreage and enabled unique acreage utilization decisions in terms of well placement and lateral trajectory.
Zhan, Lang (Shell International Exploration and Production Inc.) | Tokan-Lawal, Adenike (Shell Exploration and Production Co.) | Fair, Phillip (Shell International Exploration and Production Inc.) | Dombrowski, Robert (Shell International Exploration and Production Inc.) | Liu, Xin (Shell International Exploration and Production Inc.) | Almarza, Veronica (Shell Exploration and Production Co.) | Girardi, Alejandro Martin (Shell Exploration and Production Co.) | Li, Zhen (Shell Exploration and Production Co.) | Li, Robert (Shell Exploration and Production Co.) | Pilko, Martin (Shell Exploration and Production Co.) | Joost, Noah (Shell Exploration and Production Co.)
Summary Hydraulic fractures play a central role in the performance of multistage fractured horizontal wells (MFHWs) in tight and shale reservoirs. Fracture conductivity variations and connection quality between fractures and wellbore (i.e., choking skins) strongly affect well productivity. However, convincing and high-quality evaluations of hydraulic fractures for these reservoirs are rare in literature because quantifying fracture properties requires decoupling them from fracture geometry and formation properties, a difficult task in most field conditions. A data gathering and hypothesis testing program was implemented using six multifractured horizontal wells in a pad in the Delaware Basin to improve our ability to reliably forecast well performance. A systematic approach utilizing production, shut-ins, and bottomhole pressure measurements (BHP) was conducted and used to evaluate the apparent flow capacity of hydraulic fractures. Two independent techniques were used in the data analyses to characterize the hydraulic fractures; namely, pressure transients for individual wells and significant well-to-well interference signals. Both techniques render similar decline rate interpretations for the sets of fracture conductivity/permeability from analysis of the pressure data, but there is a large difference in the uncertainty of the estimated results from these two methods. The first method used a radial/linear flow regime in successive pressure buildups in three of the six wells. Simulations and theoretical analysis show that this flow regime allows decoupling fracture conductivity from fracture geometry and matrix properties. This flow regime yields the total apparent fracture conductivity (TAFC), which represents the lump sum effect of fracture conductivity. In addition, this technique characterizes the connection condition between the dominant fractures and borehole, which can be estimated from the early derivative horizontal line in pressure transient log-log diagnostic plots with minimum assumptions. Specifically, the estimated TAFC ranges from 1,140 to 1,630 md-ft at early time of well life to 525 to 855 md-ft after 100 to 139 days in production, or about a 45 to 61% reduction among these wells. The second method uses time-lag of pulse interference responses between an active and observation well. With assumptions of low, mid, and high values of fracture porosity, fracture compressibility, and fluid viscosity, characteristic fracture permeability can be estimated. Because of the large uncertainty related to the assumed fracture porosity and fracture compressibility, the pulse interference method is not likely to deliver the same certainty range as successive pressure buildups using the radial/linear flow regime. The results of this work provide a better understanding of the mechanisms of flow transport inside hydraulic fractures and at the connection between the hydraulic fractures and wellbore. The estimated TAFC and its significant decline help improve hydraulic fracturing designs and build representative reservoir models for more reliable well performance modeling and forecasting.
Canbaz, Celal Hakan (Ege University) | Deniz-Paker, Melek (Petroleum Experts LLC) | Hosgor, Fatma Bahar (Petroleum Experts LLC) | Putra, Dike (Rafflesia Energy) | Moreno, Raul (Smart Recovery) | Temizel, Cenk (College of Technical Studies) | Alkouh, Ahmad (College of Technical Studies)
Abstract Geochemistry is not only a well-known tool in providing a better understanding of the distribution of fluids in the reservoir rock but also an efficient kit in developing reservoir by decreasing the uncertainty throughout the characterization process. Utilizing geochemistry, not only efficiently identify the fluids and type of oil alteration drastically laterally and vertically over short distances in heavy oil reservoirs where such differences are of significant importance in production of heavy oils in these already challenging reservoirs, but also outline the value of geochemistry to justify the value of information in the process of more robust reservoir characterization and management of heavy oil reservoirs. A conceptual model representative heavy oil reservoir recovery is utilized to compare the recoveries between a case where geochemistry is applied to characterize the reservoir and another case where geochemical methods are not employed by using a full-physics commercial reservoir simulator. A sensitivity and optimization software is coupled with the reservoir simulator to outline the relative significance of the important parameters in the recovery process. Geochemical characterization, not only, provides information on gas content and its likely behavior where it can also lead to better decisions on completion strategies to avoid zones of different viscosity, but also the essential correlation between the geochemistry and the thermodynamics of heavy oil. Comprehensive reservoir characterization leads to a more robust identification of reservoir fluids where such knowledge will greatly enhance the efficiency thus the economics of the process that is especially important in low oil price environments. There is lack of studies recently on the application of geochemical characterization on the recovery of the process analyzing the relative significance of components, key drivers and the value of the information throughout the process, even though some authors have been published their research on geochemistry and its use in the characterization of the reservoirs. Our study outlines a comprehensive background including latest developments, investigates the key factors, and the value of information on comparative cases considering the relevant components of the process.
Abstract The completion design process for most horizontal wells in shale reservoirs has become a statistical evaluation process, rather than an engineering-based process. Our paper presents an alternative approach using an engineering approach to define the reservoir properties and the effectiveness of the fracture treatments. We then use these results in an economic analysis that allows the engineer to be predictive with respect to how capital is spent in the completion process. This paper presents a methodology for both the evaluation of the reservoir and the design of the well completion where the engineer can make economic decisions and determine the change in the return on investment as a function of the change in capital expenditure. The engineer can then be able to “optimize” the completion and fracture treatment designs based on Net Present Value, Return on Investment or any other economic parameter desired. We use a rate transient analysis approach to estimate reservoir and fracture properties. We present case histories in the paper, and the interpretation of the production analyses of these case histories yields information about the formation permeability and the effective lengths and number of hydraulic fractures created during the completion process. With knowledge of the reservoir and fracture properties in hand, the engineer can then determine the “optimum” completion design for future wells. This understanding can be achieved much quicker and for much less money than the cost to drill the number of wells necessary to make statistical analysis meaningful. The results of the case histories indicate that many completion designs are not in the “optimum” range. Too much capital is being spent increasing stage count when it should be going to increased effective length. The focus on early-time production has ignored the effect that more fractures has on ultimate recovery. The results and conclusions in this paper will run contrary to much of the direction most unconventional completion designs have been evolving over the past 5 to 10 years. A much greater emphasis on achieving increased effective lengths will be demonstrated and that increased stage count can prove detrimental to economic success over the well's life. Processes in the paper will also prove valuable for smaller operators that do not have a large well counts that are usually required to achieve a meaningful statistical evaluation.
Panja, Palash (Department of Chemical Engineering, and Energy & Geoscience Institute, University of Utah) | Velasco, Raul (Energy & Geoscience Institute, University of Utah) | Deo, Milind (Department of Chemical Engineering, University of Utah)
Abstract In this work, we estimate the Stimulated Original Oil In Place (SOOIP) of hydraulically fractured horizontal wells in prominent shale plays. This is done by compiling production data from hundreds of wells belonging to the Bakken, Niobrara, Wolfcamp, Eagle Ford, Bone Springs, and Woodford totaling over 2,500 wells. Additionally, we present probabilistic distributions of SOOIP with mean, standard deviation, P10, P50, and P90 estimates for each play. To circumvent the challenge of data availability for each well, we use the findings of a previous study where all reservoir unknowns are grouped into two major parameters. One of these parameters, alpha, is a function of the stimulated reservoir volume, compressibility, and pressure drawdown, where the last two are unknowns. While alpha is determined with high confidence for each well, we account for the uncertainty of compressibility and drawdown values across wells by assuming a normal distribution for these parameters. Lastly, by incorporating 1 million Monte Carlo samplings and a Mersenne Twister random number generator we estimate SOOIP distributions for each play with varying degrees of confidence. The final results show that the Niobrara and Bakken have the highest mean SOOIP values per well while the values for the Woodford and Bone Springs are the lowest among all six plays considered. Volumetric calculations using data from the literature qualitatively corroborate these findings. New insight on the stimulated volumes per well for prominent shale plays can be derived from these results as they correlate to horizontal well length, formation thickness, and hydraulic fracture half-lengths in each play.