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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 The US shale revolution in the past decade has doubled the country's crude production, and tight clay-rich formations account for 60% of the US crude production. Nevertheless, our knowledge of petroleum system controls on the reservoir performance of these tight shale systems remains poor. We report on a methodology to utilize production data to compare and rank the US shale oil plays in conjunction with geologic descriptions of the plays. For this study, we have used 36,642 horizontal oil wells from 12 tight shale formations in the Rockies and Midwest basins with vertical depths ranging from 5,000-15,000 feet and with at least 24 months of production to rank these plays based on their performance. These formations include: Wolfcamp (Delaware and Midland/Permian), Bone Spring (Delaware/Permian), Eagle Ford (Gulf Coast West and Central/ Cretaceous), Niobrara (Denver and Powder River/Cretaceous), Bakken (Williston/Devonian), Austin Chalk (Gulf Coast West/Cretaceous), Woodford (Anadarko/Devonian), Spraberry (Midland/Permian), and Barnett (Fort Worth/Mississippian). Their production data were normalized for cumulative oil (STB/ft/month), and the results were then analyzed in light of geologic and geochemical data from the formations. Integrated production and geologic-geochemical data on the tight formations offer valuable insights into the control of petroleum system elements on production patterns. These comparative patterns were used for ranking the shale plays for various parameters. In terms of cumulative oil production (STB/ft/month), Wolfcamp (Delaware) ranks top (0.93 STB/ft/month) while Barnett (Fort Worth) has the lowest crude production (0.07 STB/ft/month). In terms of GOR changes during production, Wolfcamp (Delaware) shows the lowest change (1.38 times), while Barnet (Fort Worth) has the highest change (13.37 times). These may be related to the oil-prone nature of Wolfcamp and the gas-prone characteristics of Barnet. Overall, deeper shale plays yield more oil (per foot per month) than the shallower plays. Some plays exhibit intra-formational migration of hydrocarbons. The results and the methodology of this study provide a multi-disciplinary geo-engineering to characterize shale oil plays in various basins. Variability in the performance of shale oil plays given by production data can be reverse engineered to petroleum systems.
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 This paper introduces a method for integrating gas-to-oil ratio (GOR) into existing Production Decline Analyses (PDA) that enables advanced prediction of future transitions from infinite-acting, transient flow over to boundary-dominated flow (BDF). Given the now unprecedented fraction of US oil production emanating from transient-flowing reservoirs drained with fully-bounded development wells, the longstanding use of late-life assumptions to accommodate the inevitable degradations in oil decline associated with the establishment of BDF have led to significant overestimation in oil reserves. Oil and GOR data from initial, transient flow periods are individually forecast and combined to generate gas and total energy equivalent production forecasts. The law of conservation of energy for a closed system is invoked to enable anticipatory modification of a transient forecast based on universally accepted first principles. The total energy equivalent forecast is interrogated for future indication of physically irrational, runaway increasing total energy production to provide for proactive termination of transient forecast segments. While fundamentally applicable to all forms of PDA, basic application of the technique via Decline Curve Analysis (DCA) after J. Arps (1945) is demonstrated on three field cases, two of which are individual wells with manifested prior transitions. The third case is an example of application on multiple wells simultaneously. Key sensitivities affecting this breakthrough method are demonstrated and error analysis is provided. Introduction Current estimates of US oil reserves have unaccounted for risk due to the now unprecedented fraction of domestic oil production emanating from infinite-acting reservoirs undergoing transient flow. Reservoir theory clearly indicates that strongly hyperbolic oil declines degrade significantly upon the inevitable onset of BDF. The assumptions from the prior decade have been that stimulated shale reservoirs will stay in infinite-acting, transient flow for most of their producing lives - regardless of spacing or stimulation intensity - with the inevitable transition to BDF manifesting only after multiple decades of production. This notion was without direct precedent, and much data now proves this assumption incorrect. Furthermore, no existing PDA technology provides a mechanism for predicting future transitions to BDF from infinite-acting, transient flow data. Consequently, production forecasts generated from unbounded, transient reservoir data have resulted in significant overestimation. This paper introduces a novel technology that enables the prediction of impending transitions to BDF and a mechanism for modifying forecasts to accommodate the corresponding material degradation said transitions impugn upon strongly hyperbolic oil declines.
Shammam, F. O. (Missouri University of Science and Technology) | Alkinani, H. H. (Missouri University of Science and Technology) | Al-Hameedi, A. T. (Missouri University of Science and Technology) | Dunn-Norman, S. (Missouri University of Science and Technology)
ABSTRACT: Refracturing old wells instead of drilling and stimulating new wells has become a new trend in the United States due to the oil prices falling in 2011. This work aims to disclose all refracturing activities in the most active shale play in the United States (Bakken, Niobrara, Marcellus, Permian, Eagle Ford, Barnett, and Haynesville) in terms of techniques, candidate selection, fracturing fluid types, and the number of refracs in one well. FracFocus was used to collect data of over 130,000 wells in the United States that were completed between 2013 to the end of 2019. The refractured wells were extracted from the database and the fracturing fluid types were classified as slickwater, linear gel, cross-linked gel, hybrid, and not reported treatments based on the presence of key chemical ingredients. After processing the data, there were over 1200 wells refractured across the most active shale plays in the United States. The results showed the most common fluid type used in refractured wells is hybrid. In terms of shale plays, Niobrara was the most active shale play with over 280 refractured wells followed by Bakken, Eagle Ford, Marcellus, Permian, Barnett, and Haynesville, respectively. Furthermore, the refracturing activities in each well were further analyzed and clustered into two groups; one or two refracs since some wells were refractured more than one time. However, over 95% of the wells were only refractured once. Moreover, refrac candidates can be identified based on the following factors; the original wells' cluster spacing, well spacing, proppant distribution, fracture orientation, production response from initial fracture, reservoir thickness, and permeability. The optimal ranges of the aforementioned parameters were provided to achieve the best results in terms of saving money and providing the best productivity. This will help optimizing future refracturing operations in the United States and all across the world.
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.
Colorado oil production is surging to record levels, outpacing the other major producing US states in year-over-year gains on the backs of the steady-and-predictable Denver-Julesburg (DJ) Basin and overlapping Niobrara Shale. As overall US oil output continues to surge, attention has been drawn to the Permian Basin and SCOOP and STACK plays. Operators have flocked to West Texas, southeastern New Mexico, and central Oklahoma to stake claims to land they believe will usher them into a new, leaner era for the industry. The expansive Permian alone, which covers more than 75,000 sq miles, has accounted for the bulk of US oil production increases and mergers and acquisitions over the last couple of years. Although they are intertwined and together encompass parts of Colorado border states Wyoming, Nebraska, and Kansas, the DJ and Niobrara offer a fraction of the acreage and prospective resources of the Permian.
Years in the making, the recent steady rise in drilling in the Powder River Basin of northeast Wyoming is generating excitement reminiscent of the early days of currently more-established US onshore oil plays. The upturn in activity is resulting in double-digit production growth. Wells are bubbling over with oil, and operators are bubbling over with enthusiasm. This has been most evident in recent industry presentations, where decision makers from the basin's exclusive club of operators have gushed over what is becoming a core asset in their portfolios. Given the basin's oil richness, multiple stacked horizons, and well performance and economics, "we think it's comparable and competitive with the big-name basins--whether it's the Permian, SCOOP, or STACK," Joseph DeDominic, president and chief operating officer of Anschutz Exploration, said at a recent SPE Gulf Coast Section meeting on the basin.
Colorado voters soundly defeated a measure 6 November that would have restricted the vast majority of new development in the country's fifth largest oil-producing state. The outcome was a big relief for the oil and gas industry, but its existential fight in the state hasn't ended. Proposition 112 would have required new oil and gas development in Colorado to be at least 2,500 ft from areas considered "vulnerable," including homes, schools, and waterways. The current minimum setback is 500 ft. With more than 90% of precincts reporting, about 57% of the electorate voted against the measure.