The statistical rock physics workflow developed in this paper integrates petrophysical analysis, 3D seismic data, geostatistics, and fracture modeling (and all of their respective uncertainties) into a comprehensive reservoir model to determine resource-in-place, understand well recovery factors, optimize stimulation designs and production prediction, optimize well spacing, benchmark these stock-tank original oil in place (STOOIP) calculations with actual fracturing results, and help to manage realistic expectations. Most importantly, this approach truly helps to bridge the gap between 3D seismic and geosciences for drilling engineers, reservoir engineers, reserve engineers, and completion engineers.
Detailed subsurface characterization for developing unconventional oil and gas assets is a critical component to understand where and how to drill horizontal wells, pinpoint subsurface targets, identify reservoir sweet spots, determine stock-tank original oil in place (STOOIP), optimize well spacing in a drilling spacing unit (DSU), and engineer completion designs. A new methodology was developed, using statistical rock physics techniques, to address these complex unconventional reservoir challenges. This procedure integrates petrophysics, rock typing, 3D seismic elastic properties, and geostatistics to build the reservoir model, and then directly incorporates the reservoir results into fracture model designs. This methodology was used on the Cretaceous Niobrara formation in the DJ basin where horizontal pad drilling has been in practice for several years with much experimentation by operators in terms of well spacing, stage spacing, fluids, and proppant volumes. As a result of the recent industry downturn, operators are now more focused on increasing recovery factors in a DSU while maintaining individual well economics, i.e., return on capital employed (ROCE). This new process directly addresses those concerns, which will enable Niobrara operators to make more informed decisions going forward with regard to number of wells per DSU and optimized fracture designs.
Statistical Rock Physics
An applied statistical rock physics approach for reservoir characterization integrates fundamental petrophysical concepts of effective porosity, hydrocarbon saturation, and geomechanics with statistical and non-statistical pattern recognition, 3D seismic attribute analysis, and geostatistical modeling.
Popova, Olga (Energy Information Administration, US Department of Energy) | Long, Gary (Energy Information Administration, US Department of Energy) | Little, Jeffrey (Energy Information Administration, US Department of Energy) | Mariner-Volpe, Barbara (Energy Information Administration, US Department of Energy) | Grape, Steven (Energy Information Administration, US Department of Energy)
U.S. production of tight oil and shale gas has increased significantly through the last decade. The EIA-914 began collecting natural gas production data in 2005 from 5 states (Louisiana, New Mexico, Oklahoma, Texas, and Wyoming), federal Gulf of Mexico GOM, and other states (as a group). Oil production was not included. In response to major increases in U.S. oil and natural gas production EIA has expanded its reporting of monthly hydrocarbon production to include more geographical coverage and collection of crude oil and lease condensate in addition to natural gas production in 5 states. In 2015, EIA improved the EIA- 914 form to add more states: additional states are Arkansas, California, Colorado, Kansas, Montana, North Dakota, Ohio, Pennsylvania, Utah, and West Virginia. “Other States” is much smaller now, reduced from 28 to 17, and only includes Alabama, Arizona, Florida, Illinois, Indiana, Kentucky, Maryland, Michigan, Mississippi, Missouri, Nebraska, Nevada, New York, Oregon, South Dakota, Tennessee, Virginia (17) and federal Pacific Offshore. Also, EIA continues its efforts to map hydrocarbon resources related to low permeability plays. Mapping in this case involves taking locational data in three dimensions (oil and gas well latitude and longitude, and the depth and thickness of shale and other tight formations) and then rendering the information as a two-dimensional representation including structure, thickness, and reservoir property maps. Collectively, EIA-914 crude oil and natural gas production data and EIA’s mapping project outcomes improves EIA reporting and forecasting, and helps inform policy makers and general public on topics such as hydrocarbon production, refining capacity, and energy legislative initiatives.
EIA’s projections are not predictions of what will happen, but rather modeled projections of what may happen given certain assumptions, methodologies, and analytical techniques. The hydrocarbon module of the Short-Term Energy Outlook (STEO) model is designed to provide forecasts of U.S. production, consumption, refinery inputs, net imports, and inventories. The Annual Energy Outlook (AEO) is developed using the National Energy Modeling System (NEMS), an integrated model that aims to capture various interactions of economic changes and energy supply, demand, and prices. Energy market projections are subject to much uncertainty, as many of the events that shape energy markets and future developments in technologies, demographics, and resources cannot be foreseen with certainty.
Liu, Kouqi (University of North Dakota) | Ostadhassan, Mehdi (University of North Dakota) | Gentzis, Thomas (Core Laboratories) | Carvajal-Ortiz, Humberto (Core Laboratories) | Bubach, Bailey (University of North Dakota)
As a typical unconventional resource located in North America, Bakken Formation has become one of the largest shale oil plays in the world. Pore structures and geochemical properties of the shale rocks are important parameters affecting the storage ability and mechanical properties. In this paper, we collected four shale rocks from Bakken Formation for the analysis. We applied SEM to qualify the microstructures of the shale rocks and then analyzed their mineral compositions by using EDX (Energy-dispersive X-ray spectroscopy). For the geochemical properties, Rock- Eval 6 pyrolysis and optical microscopy armed with reflected white light and UV light were used to get the chemical information of the samples such as organic richness, kerogen type, and thermal maturity. We also cleaned the samples to study the impact of the OBM (oil based mud) on the geochemical properties. The results showed that various pores structures exist in the shale rocks. Shale rocks in Bakken Formation have high TOC. VRo and Tmax indicate that the organic matter is in the oil window and consists of a mixture of Type II and Type III (oil/gas prone). The samples after cleaning have smaller TOC values and S1, S2 values.
Due to the depletion of the conventional resources and increasing energy demand, unconventional reservoir plays are becoming the important contributions to the world oil and gas total production (Liu et al., 2017). The Bakken Formation, located in the Williston Basin in Montana, North Dakota, and southern Saskatchewan is now the second largest oil field in the US and one of the biggest shale oil fields in the world. Based on the lithology difference, The Bakken Formation can be divided into three members. Upper and Lower Bakken Formation are world-class source rocks and the published estimates of oil generated from the source rocks range from 10 to 400 billion barrels (Sonnonberg et al., 2011). Pore structure properties analysis can assist in accurately understanding the storage and migration properties of the gas and oil while geochemical analysis can help us to assess the quantity, quality, and thermal maturity of the sedimentary organic matter (Carvajal-Ortiz and Gentzis, 2015). In this paper, we picked samples from the Upper and Lower Bakken Formation. We applied SEM to visualize the pore structures and utilized Rock-Eval and vitrinite reflectance to characterize the geochemical properties.
Organic-rich mudrocks (ORM) from the Brushy Canyon Formation in west Texas were deposited in the Middle Permian during the Guadalupian epoch in the Delaware Basin. Brushy Canyon ORM were examined for Re-Os isotope systematics with a goal of constraining their depositional age, the 187Os/188Os value of seawater at their time of deposition, and to examine how Re and Os partition into organic material in ORM. For these samples, Rock-Eval pyrolysis data (HI: 228-393 mg/g; OI: 16-51 mg/g) indicates predominantly Type II marine kerogen with minor contributions of Type III terrestrial organic matter. Rhenium and osmium abundances correlate positively with HI, and negatively with OI, which are proxies for organic matter type and degree of preservation. These data are consistent with previous work that indicates Re and Os abundances are controlled by the availability of chelating sites in the kerogen. Brushy Canyon Formation samples have (total organic carbon) TOC values between 0.97 and 4.04% and show a strong positive correlation with both Re and Os abundances, consistent with correlations between these parameters in other ORM suites. The positive slopes in these correlations are distinct between marine (higher slopes) and non-marine (lower slopes) lacustrine environments of deposition. The Brushy Canyon’s steep slopes are consistent with marine deposition of its organic matter and an open-ocean non-restricted setting. The relationship to other Re-Os and TOC data sets appears to be a function of the restrictivity of marine conditions, and associated variations in reducing conditions during ORM accumulation of the Delaware Basin compared with more restricted lacustrine basins with local drawdown of Re and Os.
The Re-Os isotope systematics of ORM from the Brushy Canyon Formation yields a Model 1 age of 261.3 ± 5.3 Ma (2.0% age uncertainty; MSWD = 0.82). Within the uncertainty, this agrees with the expected Guadalupian age for this formation. This Re-Os age represents the first direct, absolute age for Guadalupian organic matter in the Delaware Basin. The initial (187Os/188Os)i = 0.50 ± 0.06 obtained by isochron regression represents the 187Os/188Os of seawater at this time. This value is significantly less radiogenic than modern day seawater (~1.06). The lower 187Os/188Os of Guadalupian seawater recorded is likely caused by a decrease in the relative flux of radiogenic Os from continental weathering due to a number of local and global climatic and tectonic changes that were occurring during this time.
The pioneering shale gas plays -- the Barnett and Fayetteville -- have become increasingly mature and today are several years past their prime. From a peak of 5.7 Bcfd in 2012, the Barnett has declined to 3.5 Bcfd of natural gas production (wet) in early 2017. Similarly, natural gas production from the Fayetteville Shale, that maintained its peak production of 2.8 Bcfd from 2012 through 2014, has declined to 1.7 Bcfd in early 2017, Exhibit 1.
The pioneering shale/tight oil plays - - the Bakken and Eagle Ford that sparked the “tight oil” revolution - - each now contain over 10,000 horizontal wells that have significantly depleted their core (“sweet spot”) areas. The combination of “core” area resource depletion, lower oil prices, and the subsequent sharp drop in rigs has caused oil production from these two shale oil plays to also enter decline, Exhibit 2.
At some point, even the massive Marcellus/Utica shale gas plays and the equally massive Permian shale/tight oil resources will become mature with their “core” areas fully developed.
As such, the question becomes - - what set of shale and tight formation plays and resources will emerge to replace these increasingly mature, pioneering plays, enabling domestic shale gas and shale/tight oil production to continue to grow?
Perspective on Emerging Unconventional Resources
Our perspective is that new domestic unconventional shale and tight sand resources will continue to emerge, but often following pathways other than the classical “new discoveries and rediscoveries.” While “newly discovered and rediscovered” shale and tight oil and gas plays will emerge from the innovative minds of unconventional oil and gas explorers, much of the new shale and tight resource will stem from alternative pathways.
Alternative Pathway #1. Looking In Your Own Back Yard. The first alternative pathway for adding unconventional resources is the search for additional productive horizons in existing basins, such as the Meramec Formation above the Cana-Woodford Shale in the Anadarko Basin and the Moorfield Shale below the Fayetteville Shale in the Arkoma Basin. Currently, the most extreme opportunities for “looking in your own backyard” involves “dealing with a stacked deck” - - the host of shale and tight sand plays in the Permian Basin.
Distributed Acoustic Sensing (DAS) optical fiber for downhole geophysical measurements is a fairly new technology the industry is utilizing to better characterize hydraulic stimulations. Data were acquired with a vertical observation well that was instrumented externally with dual and single mode fiber optics for strain, acoustics (DAS), temperature (DTS), and external pressure gauges as well as internally instrumented with conventional tiltmeters and geophones. We used this instrumented well multiple times to record a number of nearby offset horizontal hydraulic stimulations as well as for a 3D 4D vertical seismic profile (VSP).
By using several tools, we can more accurately determine the height and length of the hydraulically stimulated zone to calibrate fracture models and determine where to place future horizontal wells during our field development.
While numerous papers can be written about the data collected, this paper focuses mainly on the microseismic data acquired with fiber. We have made the following observations using these microseismic data:
Klokov, Alexander (The University of Texas at Austin) | Repnik, Alexander (PerPetro) | Bochkarev, Vitaliy (Lukoil International Upstream West Inc.) | Bochkarev, Anatoly (Gubkin Russian State University of Oil and Gas)
The major unconventional play in the Cooper Basin, South Australia, is the Roseneath - Epsilon - Murteree (REM) interval that spans the tight Epsilon sand confined between Roseneath and Murteree shales. In this work, we evaluate the REM formations in the vicinity of well Moomba-191, which provided the first commercial gas flow. We investigate seismic diffractions to explain the high production rates from Moomba-191. In addition, we seek correlations between seismic diffractivity and the formation properties, total organic carbon (TOC), maturity, brittleness, to suggest an optimal approach to the play exploitation.
Seismic diffractions are direct indicators of subtle subsurface features like small-throw faults, fractures, or local hydrocarbon accumulations. The 3D diffraction image we obtained is validated by comparison with curvature attributes. We observe that strong diffractions are consistent with most-negative curvature. Most-positive curvature, in turn, is consistent with low-diffractivity quiet zones. This observation suggests that diffractivity in the area is mostly caused by formation bending and is concentrated in local troughs. Diffraction imaging revealed a high-amplitude diffraction anomaly associated with the Moomba-191 well. In addition, the diffraction image suggests that the high-diffractivity zone is hydraulically connected with underlying gas-rich formations. The hypothetic connectivity (likely provided by fracturing) could explain the high production rates from the Moomba-191 well.
We next predict petrophysical properties of the Murteree shale, which provided the highest production rates, to correlate them with detected seismic diffractivity. We start with one-dimensional basin modeling and well log analysis to evaluate the catagenesis gradation and conclude with recommendations about potential gas generation and presence. We determine TOC values in the Moomba-191 well by the Passey methodology and complement this information with brittleness estimates. Then we perform seismic inversion to obtain P-wave impedance. Based on correlation between P-impedance and TOC and between P-impedance and brittleness at the Moomba-191 location, we obtain spatial distributions of TOC and brittleness over the prospect area. In the further analysis, we treat these estimates with caution because the inversion results could be negatively impacted by significant multiplies caused by numerous coal intervals.
The proper design and execution of a drawdown schedule for hydraulically fractured wells in overpressured, tight reservoirs is an important step to maintain well productivity and protect against fracture damage. To accurately design a drawdown plan requires knowledge of how stresses will evolve in the subsurface. Calculating dynamic stress changes during reservoir depletion, however, typically requires coupled-geomechanics simulators which are very specialized and time-consuming tools. In this work, we develop a methodology using analytical models to quickly estimate reservoir stress changes and predict effective stress on the fracture network in real-time.
In tight reservoirs, the drawdown management procedure has a direct link to flowing bottomhole pressure and the resulting stress on the proppant pack. To estimate the effective stress on the hydraulic fractures over time, a series of coupled-geomechanical models were built using realistic formation properties. These geomechanical modeling results were then used to calibrate an analytical model based on poroelastic theory. The analytical model is able to accurately reproduce the coupled-geomechanical results across a wide range of depletion scenarios with a small margin of error. Once calibrated, the analytical model can be used to quickly estimate the stress on the fracture network during routine well surveillance.
A case study will be shown demonstrating how the workflow led to field decisions in a high pressure unconventional reservoir in North America. After careful analysis of lab-measured fracture conductivity, the decision was made to decrease the production rate in order to keep the stress on the fracture network below a threshold value where reduced fracture conductivity was observed. The well with this managed drawdown schedule has maintained well productivity and has not flowed damaged proppant fines to surface in contrast to observations from other wells in the field. This workflow has improved the asset team’s ability to predict, identify, and mitigate fracture damage on unconventional horizontal wells, thereby avoiding the loss of estimated ultimate recovery (EUR) and enhancing project economics.
Folio, Erica (Office of Oil and Natural Gas, Department of Energy) | Ogunsola, Olayinka (Office of Oil and Natural Gas, Department of Energy) | Melchert, Elena (Office of Oil and Natural Gas, Department of Energy)
Since its inception in the late 1970’s, the United States Department of Energy’s (DOE) Office of Oil and Natural Gas (ONG), in partnership with industry, national laboratories, universities, and other entities, has conducted research and development (R&D) to support the safe and prudent development of the United States’ vast unconventional oil and gas (UOG) resources. UOG resources, by virtue of their abundance and geographic distribution, are vital to national economic and energy security, and support energy independence. The goal of DOE’s research of unconventional oil and gas resources is to develop advanced technology that can enable the production of UOG resources with the smallest surface footprint and that can protect water resources, reduce water use, protect air quality, and address induced seismicity. DOE works to ensure the public good, through relatively early-stage (low technology readiness level) research and technology development, and puts that technology, information, and all results into the public domain.
Wellbore integrity is key to achieving’s DOE’s mission. When the seals that are designed to ensure zonal isolation fail to perform adequately, unintended communication can occur between the interior and exterior of the well. A loss of wellbore integrity can undermine proper stewardship of resources, result in a loss of resource productivity, groundwater contamination, surface water contamination, emission of pollutants into the atmosphere, and, in extreme cases, serious impacts on human health and safety. Minimizing or eliminating these risks is a high-priority public concern, and a high priority for DOE.
Considering importance of unconventional oil and gas resources to the energy and economic security of the United States, it is critical that these wellbore integrity challenges be addressed. This paper presents an overview of DOE - funded research projects that address onshore UOG wellbore integrity. Wellbore integrity research, including experimental efforts, numerical modeling, and innovative technology development, is a critical facet of DOE’s research portfolio. The project portfolio includes planning and risk assessment; developing dependable materials and monitoring technologies, and reliable remediation methods.
We investigated geological, petrophysical, rock physics and engineering properties of resource shales using well data and core samples from three continents. The North American Utica-Point Pleasant example, spanning carbonates, marls and shales, came from the base of the oil window in this play. Extremely high resistivity invalidated the Passey method for total organic carbon (TOC) calculation, while elevated uranium marked the original source beds rather than the maximum of organic matter found in underlying carbonates where pyrobitumen is abundant. A 1 GHz dielectric log enabled us to develop a new crossplot where matrix, water and organic matter effects could be differentiated. The North American Marcellus shale example represented the other extreme of thermal maturity, where vitrinite reflectance exceeds 4 % Ro and the organic matter is partly transformed to highly conductive proto-graphite, again complicating petrophysical interpretations. The Chinese Longmaxi shale has classical “hot shale” characteristics where U content from logs or core scanning gives a good estimate of TOC. In both cases, siliceous matrix may be advantageous in terms of rock brittleness but may lock up gas in inaccessible pores. The Roseneath and Murteree Shales of the Australian Cooper Basin represent a hybrid shale/tight gas resource play where Gas in Place (GIP) is dominated by free gas, largely sourced from nearby coals, in inter-mineral pore space. Dielectric responses of lab samples show a linear relationship between water content and permittivity, however no downhole dielectric logs are yet available to evaluate this approach to identify sweet spots. Aside from using advanced petrophysical and microstructural methods we gained insights from standard log correlations. We found that neutron porosity alone could entirely predict the organic-free (background) resistivity log response in the Murteree shale via the non-linear equation: 1/R_t = C [*NPHI] ^d. We propose that hydrated cation conductivity determines the pre-factor C, while pore geometry/topology determine the value of exponent d. The application of such nonlinear relationships to modern machine learning methods warrants further investigation.