With the increasing demand for hydrocarbons, unconventional reservoirs are gaining prominence and account for a large percentage of oil and gas production. However, these unconventional reservoirs inevitably include challenges that must be carefully managed while planning an extraction strategy to yield maximum recovery. This paper demonstrates the advantages of an integrated and automated well placement workflow to improve geosteering in complex unconventional reservoirs with maximum hydrocarbon recovery.
Automated well placement technique is controlled by three primary components: (1) an integrated asset model; (2) availability of uninterrupted, real-time log data; and (3) appropriately selected well planning methods. Initially, a dynamically updatable model of subsurface geology is created that combines surface topography, and an initial well trajectory is planned. As the well progresses, new log data are added to the asset model, and an interpretation is made in real time. Incorporating real-time data helps to dynamically update the model and enable a comparison of planned vs. actual deviation surveys for course corrections. This procedure guides the geosteerer to update well plans, run feasibility analyses, and predict subsurface uncertainties ahead of drilling, thus, increasing the reservoir penetration and overall well productivity.
Automated well placement while drilling is a relatively new concept and requires collaboration across various disciplines. Currently, such techniques are gaining importance among operators of unconventional resources as it enhances accuracy in well positioning and provides better production while reducing costs, drilling risks, and uncertainties. In addition, when targeting very thin, geologically complex reservoir layers, it provides a holistic view of the dynamically changing asset. The use of this approach will enable oil and gas operators to make collaborative, cross-domain decisions and streamline existing unconventional workflows.
Morales, Adrian (Chesapeake Energy Corp.) | Holman, Robert (Chesapeake Energy Corp.) | Nugent, Drew (Chesapeake Energy Corp.) | Wang, Jingjing (Chesapeake Energy Corp.) | Reece, Zach (Chesapeake Energy Corp.) | Madubuike, Chinomso (Chesapeake Energy Corp.) | Flores, Santiago (Chesapeake Energy Corp.) | Berndt, Tyson (Chesapeake Energy Corp.) | Nowaczewski, Vincent (Chesapeake Energy Corp.) | Cook, Stephanie (Chesapeake Energy Corp.) | Trumbo, Amanda (Chesapeake Energy Corp.) | Keng, Rachel (Chesapeake Energy Corp.) | Vallejo, Julieta (Chesapeake Energy Corp.) | Richard, Rex (Chesapeake Energy Corp.)
An integrated project can take many forms depending on available data. As simple as a horizontally isotropic model with estimated hydraulic fracture geometries used for simple approximations, to a large scale seismic to simulation workflow. Presented is a large-scale workflow designed to take into consideration a vast source of data.
In this study, the team investigates a development area in the Eagle Ford rich in data acquisition. We develop a robust workflow, taking into account field data acquisition (seismic, 4D seismic and chemical tracers), laboratory (geomechanical, geochemistry and PVT) measurements and correlations, petrophysical measurements (characterization, facies, electrical borehole image), real time field surveillance (microseismic, MTI, fracture hit prevention and mitigation program through pressure monitoring) and finally integrating all the components of a complex large scale project into a common simulation platform (seismic, geomodelling, hydraulic fracturing and reservoir simulation) which is used to run sensitivities.
The workflow developed and applied for this project can be scaled for projects of any size depending on the data available. After integrating data from various disciplines, the following primary drivers and reservoir understanding can be concluded. At a given oil price, optimum well spacing for a given completion strategy can be developed to maximize rate of return of the project. Many operators function in isolated teams with a genuine effort for collaboration, however genuine effort is not enough for a successful integrated modelling project, a dedicated multidisciplinary team is required.
We present what is to our knowledge, one of the most complete data sets used for an integrated modelling project to be presented to the public. The specific lessons from the project are applied to future Eagle Ford projects, while the overall workflow developed can be tailored and applied to any future field developments.
The objective of our research is to reconcile the differences, in both age and relative stratigraphic position, between the Woodbine and Eagle Ford Groups in the outcrop and subsurface of the East Texas Basin. In the outcrop belt, organic- and carbonate-rich Middle Cenomanian mudstones are mapped within the Eagle Ford Group, where they overlie, and are separated by a regional unconformity from Early Cenomanian, organic-poor, and clay-rich mudstones of the Woodbine Group (Pepper Shale). In southern portions of the East Texas Basin, however, these same organic- and carbonate-rich Middle Cenomanian mudstones are mapped within the Maness Shale, which in turn, is overlain by Late Cenomanian to Turonian-aged mudstones (Pepper Shale) and sandstones (Dexter Formation) mapped as the Woodbine Group. Our approach to reconcile the lithostratigraphic juxtaposition between the two regions was to use chemo-stratigraphic and petrophysical data collected from the outcrops, as well as an adjacent shallow research borehole, in order to define key sequence stratigraphic units/surfaces, and then correlate the key units/surfaces from the outcrop belt into the subsurface.
Our research indicates that the Woodbine Group, is an older unconformity-bounded depositional sequence which is Early Cenomanian, whereas the Eagle Ford Group, is an overlying (younger) unconformity-bounded depositional sequence, which is Middle Cenomanian to Late Turonian. The unconformities that bound these units can be mapped from the outcrop belt into the subsurface of the East Texas Basin, to define coeval depositional sequences. As defined in this study, marine mudstones of the Woodbine Group, are clay- & silica-rich, TOC-poor, and characterized by low resistivity on geophysical logs. In general, the Woodbine Group thins, as well as transitions to more mudstone-prone facies, from northeast to southwest within the basin. While beyond the scope of this study, the Woodbine Group contains numerous higher-frequency sequences, which are stacked in an overall progradational (highstand) sequence set. The depositional profile of the unconformity which forms the top of this progradational succession sets up the relict physiographic (depositional shelf/slope/basin) profile for the overlying Eagle Ford Group.
Within the Lower Eagle Ford Formation, two high-frequency sequences, defined as the Lower and Upper Members, were defined. Within the Upper Eagle Ford Formation, three high-frequency sequences, defined as the Lower, Middle, and Upper Members, were defined. The Lower and Upper Members of the Lower Eagle Ford Formation, as well as the Lower Member of the Upper Eagle Ford Formation range from Middle Cenomanian to Early Turonian. These three high-frequency sequences contain marine mudstones that are carbonate- & TOC-rich, as well as clay- and quartz-poor, and are characterized by high resistivity values on geophysical logs. Furthermore, they are interpreted as a transgressive sequence set, with sequences that sequentially onlap, from older to younger, the inherited relict physiographic (depositional shelf/slope/basin) profile of the underlying Woodbine Group. In stark contrast, mudstones within the Middle and Upper Members of the Upper Eagle Ford Formation, which are Middle to Late Turonian, are clay-rich, TOC-poor, and characterized by low resistivity on geophysical logs. These two sequences, which are interpreted as a highstand sequence set, are sandstone-prone, and contain petroleum reservoirs that previously were incorrectly included within the Woodbine Group. Based on these correlations, updated sequence-based paleogeographic maps can be constructed for the first time across the East Texas Basin. These maps can in turn be used to define a robust portfolio of conventional, as well as unconventional tight-rock and source-rock, plays and play fairways, which are now based on a modern sequence stratigraphic, versus the traditional archaic lithostratigraphic framework.
Geochemical data measured on oil samples produced from wells landed in the Austin Chalk, the Eagle Ford Formation, and the Buda Formation and on petroleum samples sequentially extracted from Upper Eagle Ford and Lower Eagle Ford marl and calcareous shale core pucks using several solvents were used to estimate the amount and properties of producible oil, immobile adsorbed/dissolved oil, and non-producible bitumen in those core samples. Crushed core samples obtained from two monitor wells located on the San Marcos Arch where Eagle Ford source-rock beds have reached different levels of maturity were sequentially extracted using a weak solvent (cyclohexane; CH), two stronger solvents (toluene and DCM), and a very strong solvent (chloroform-methanol; CM). Similar geochemical data were measured on the core extracts (after heating them to evaporate the solvents), and on native and topped oil samples. The CH extracts exhibit n-alkane profiles characteristic of crude oil, but extracts obtained using stronger solvent do not resemble oil. C15-C35 HC compounds present in produced oils are more abundant in CH extracts (which principally contain producible oil and adsorbed/dissolved oil) than in extracts obtained using stronger solvents (which principally contain bitumen). The SARA composition of topped oil samples also is more similar to the composition of core extracts obtained using CH than extracts obtained using stronger solvents (which contain significantly more resins and asphaltenes). The extract obtained from lower-maturity marl core pucks using CH contains much more sulfur (≈4.4 wt%) than the CH extract obtained from more thermally mature marl core pucks (≈2.0 wt%). Calibrations between the API gravity, C7 temperature, and sulfur content of native and topped oil samples were used to estimate the gravity and sulfur content of core extracts obtained using different solvents. The amount of resin-rich immobile oil in the core extracts was estimated using reasonable assumptions about the composition of that component. The Lower Eagle Ford marl at the higher-maturity monitor well contains ≈0.35 wt% of ≈30-31°API producible oil and ≈0.27 wt% of non-producible bitumen. That reservoir contains only ≈0.12 wt% of ≈27°API producible oil and ≈0.38 wt% of non-producible bitumen at the lower-maturity monitor well. The LEF calcareous shale contains approximately the same amount of producible oil as the overlying marl at the more mature monitor well, but it contains much less non-producible bitumen (≈0.12 wt%).
Raterman, Kevin T. (ConocoPhillips) | Farrell, Helen E. (Twenty-Sixth Street Consulting) | Mora, Oscar S. (ConocoPhillips) | Janssen, Aaron L. (ConocoPhillips) | Gomez, Gustavo A. (ConocoPhillips) | Busetti, Seth (ConocoPhillips) | McEwen, Jamie (ConocoPhillips) | Friehauf, Kyle (ConocoPhillips) | Rutherford, James (ConocoPhillips) | Reid, Ray (ConocoPhillips) | Jin, Ge (ConocoPhillips) | Roy, Baishali (ConocoPhillips) | Warren, Mark (ConocoPhillips)
Kevin T. Raterman, ConocoPhillips; Helen E. Farrell, Twenty-Sixth Street Consulting; and Oscar S. Mora, Aaron L. Janssen, Gustavo A. Gomez, Seth Busetti, Jamie McEwen, Kyle Friehauf, James Rutherford, Ray Reid, Ge Jin, Baishali Roy, and Mark Warren, ConocoPhillips Summary Between 2014 and 2016, ConocoPhillips drilled five deviated wells adjacent to a multistage, stimulated horizontal producer to sample the physical characteristics of the reservoir stimulation caused by hydraulic fracturing in the Eagle Ford Formation in DeWitt County, Texas. The design, execution, and results of the pilot are described. This pilot establishes the paucity of preexisting natural fractures in this locale and enables the determination of the spatial characteristics of the stimulation using information derived from the core, cuttings samples, borehole-image logs, tracer logs, microseismic, distributed temperature sensing (DTS)/distributed acoustic sensing (DAS), and pressure data.
Tight reservoirs with low and ultralow permeability must be successfully stimulated to produce at economic oil or gas rates. For this reason, costs of drilling and completing wells are very high in tight reservoirs. In order to reduce these costs, operators have often tried to replicate the same or similar hydraulic fracturing designs that have been successfully used in previous wells in the same geological area. This strategy sometimes results in unexpected surprises and operational challenges leading to unsuccessful stimulations and poor production performance. The major reason behind these challenges is that tight reservoirs exhibit a localized behavior with changes in reservoir quality such as mineralogy, hydrocarbon content, and thickness across the same reservoir.
In order to study the localized behavior of tight reservoirs; three wells that penetrated the Eaglebine formation in Texas were evaluated. The Eaglebine formation contains both the Eagle Ford and the Woodbine reservoirs. The combined Eagle Ford and Woodbine (Eaglebine) reservoir can sometimes exceed 1,000 feet in thickness. These reservoirs are present at depths between 6,500 and 15,000 feet in East Texas. In some areas, the Eaglebine contains a large percentage of silica-rich sands interbedded in organic rich shale and carbonate layers.
This paper investigates the reasons as to why same hydraulic fracturing techniques should not be applied necessarily for every well in the same geological area. Furthermore, it demonstrates how we can exploit the localized reservoir behavior to plan for future wells despite limited data availability. Data from mud logs, well logs, and cores, including mineralogy and geomechanical data are integrated to build the localized reservoir characterization model that can be used to plan how each individual well should be hydraulically fractured. The model provides information such as location of organic-rich zones, brittle zones, and ductile zones in a geological area. Lastly, it recommends the type of fracture fluid that can yield a successful stimulation operation in ductile or brittle zones.
Characterization of the lateral heterogeneity of reservoir properties is an important consideration during the design of horizontal completion operations in unconventional plays. Traditional geometric designs do not differentiate adjoining rocks based on lateral heterogeneity. This paper presents an academic case study from the Eagle Ford shale play in which the authors analyze and validate an engineering design using observations from an operator's completion design-based fracturing operation. The paper also proposes a low-cost, low-risk solution workflow for these unconventional reservoirs.
An unbiased and repeatable fracture stage and perforation cluster optimization program was used for the engineered design. The input for the engineered design originated from a two-dimensional (2D) petrophysical and geomechanical model. This model was constructed using correlative property modeling that used openhole (OH) logs from an offset vertical well and a calibrated casedhole (CH) pulsed neutron log (PNL) that was acquired in the lateral. A conventional OH logging suite was also run in the same lateral, which was compared to the calibrated log data as a part of the validation process.
The resultant 2D property model provided an appropriate representation of the subsurface reservoir properties. Lateral variations of those properties were duly addressed by optimizing the fracture stage and perforation clusters. This workflow also accounted for the relative position of the wellbore, with respect to the stratigraphic and the reservoir boundaries, as predicted by the 2D property model. During execution of the operator's completion design, reservoir properties were carefully observed and compared with those predicted by the 2D property model and the engineered design derived from the same. These observations validated the properties and justified the optimizations in the completions program and the modifications necessary. For example, a number of stages during the stimulation treatment were initially unsuccessful, thus allowing less than 10% of the total designed proppant to be pumped. During evaluation of the post-stimulation results, it was observed that these zones were identified as less promising by the 2D property model-derived engineered design because of unfavorable reservoir properties. The engineered design model recommended not completing these zones.
The observations from this study showed that completion operations in a long lateral should be designed to account for the lateral variability of the reservoir. The engineered completion design optimized hydraulic fracture stages and perforation clusters based on the petrophysical similarity and merits of the adjoining sections. The methods presented helped mitigate risk and supported rigless operations for characterization in a cost-sensitive environment, thus reducing the costs and effects of hydraulic fracturing operations.
Alqahtani, Adel A. (Petroleum Engineering Department and Unconventional Natural Gas and Oil Institute) | Tutuncu, Azra N. (Petroleum Engineering Department and Unconventional Natural Gas and Oil Institute)
Organic-rich shale formations have unique properties that significantly differ from conventional formations because of low permeability, anisotropy and multiscale heterogeneity. These properties are the results of lithology variation, depositional process, diagenesis, fabric and thin lamination, pore structure as well as the distribution and maturity of the organic matter which influence the rock properties and wave velocities. In this paper, the influence of rock composition, organic matter (TOC) and orientation of formation lamination on acoustic velocity in organic-rich shales was experimentally evaluated. A correlation was developed describing the dependence of the compressional wave velocity on stress, rock composition, organic matter, rock lamination orientation as well as the fluid composition.
After its development using core-scale measurements of the preserved shale core samples in the laboratory, the correlation was modified to include the fluid saturation using well log data in order to obtain more accurate in situ estimation of the compressional velocity. The correlation presented here can be utilized to predict velocity, TOC, and orientation of the formation lamination or potentially the in-situ pore pressure when one of the variables are unknown. The results of this study can be utilized in economic planning and optimization of the field development for organic-rich shale source rocks. Further study is in progress to verify the validity of the correlation in other shale formation field applications as the correlation presented here is specifically developed and customized for Eagle Ford shale formation.
Acoustic velocity is in general controlled by stress (Wyllie et al. 1958), lithology (Kenter et al. 1997), rock texture (Wyllie et al. 1956; Jizba 1991; Tutuncu et al. 1993; Guadagno and Nunziata 1993; Eberli et al. 2003), rock fabric (Podio et al. 1968; Nur and Simmons 1969; Vernik and Nur 1992), burial diagenesis (Schoonmaker et al. 1985; Kenter et al. 1997), pore fluid(s) type and saturation (Wang et al. 1990; Liu et al. 1994), temperature (Timur 1977; Vernik and Nur 1992), as well as signal frequency and amplitude (Tutuncu et al. 1994; 1997 a, b). In this study, several of these factors (mainly stress, rock compositions, TOC, fluid compositions and rock lamination orientation) have been evaluated with an objective of developing a correlation to understand the influence of these factors on compressional velocity in organic-rich shales.
A typical oil contains various amounts of tens of thousands of different compounds, and the relative abundances of those compounds form a “fingerprint” of that oil. This natural fingerprint can be used to answer some of the most important field-development and production-optimization questions that arise during development of unconventional reservoirs. Applications of this natural fingerprint include:
• Assessment as to whether or not induced fractures have propagated out of the formation containing a lateral and into either an overlying or underlying zone, causing the commingling of production from multiple intervals.
• Quantitative allocation of the contribution of 2-6 individual pay zones to commingled oil or gas production.
Because there are so many different compounds in an oil, even if two oils which occur in adjacent formations are 99% similar in composition, those two oils would still have more than 50 discrete geochemical differences. Any of those geochemical differences between oils from different formations could be used as natural tracers to distinguish the contribution of each reservoir to a commingled production stream.
To construct the oil fingerprint, dead oil samples are analyzed by a specialized type of high-resolution gas chromatography. In the average project, 175-250 different natural tracers are quantified in each sample, and the contribution of individual oils to a commingled sample is calculated by a linear-algebra solution of simultaneous equations, where the number of equations is equal to the number of natural tracers.
This paper illustrates these concepts using oils from 6 wells in Mitchell County, Texas in the Eastern Self of the Permian Basin.
More than 50 years ago, Jones and Smith (1965) reported compositional groupings within a set of more than 310 Permian Basin oils collected from reservoirs ranging in age from Cambrian to Cretaceous. Several years later, Kvenvolden and Squires (1967), Chuber and Rodgers (1968), Frenzel (1968), and Holmquest et al. (1968) demonstrated compositional differences among oils from various reservoirs of the Permian Basin; the differences that they noted were differences in whole oil stable carbon isotope values and molecular distributions. The technological constraints of the day prevented those authors from constructing detailed molecular fingerprints of the oils they studied. However, the whole oil isotopic data reported by Kvenvolden and Squires (1967), Chuber and Rodgers (1968), Frenzel (1968) and Holmquest et al. (1968) are still relevant to field development applications of geochemistry in the Permian Basin – even 50 years after the data were originally published.
Albrecht, Tony (Geoscience, Hawkwood Energy, Denver, CO, United States) | Kerchner, Stacy (Engineering, Hawkwood Energy, Denver, CO, United States) | Brooks, Scott (Petrophysics, Hawkwood Energy, Denver, CO, United States) | Kolstad, Eric (Drilling, Hawkwood Energy, Denver, CO, United States) | Willms, Trevor (Engineering, Hawkwood Energy, Denver, CO, United States) | Klein, John (Geoscience, Hawkwood Energy, Denver, CO, United States) | Stemler, David (Geoscience, Hawkwood Energy, Denver, CO, United States)
The Mesozoic-aged Brazos Basin, situated at the southwestern-most extent of the East Texas Basin and along trend with the Maverick Basin, is bracketed by the Edwards Reef, San Marcos Arch and the Angelina Caldwell Flexure (