The development of unconventional reservoirs require key decisions to be made under uncertainty. We regularly consider multiple variables, such as the number of wells to be placed in a section, their horizontal spacing and vertical staggering, the length and orientation of the laterals, the design of fracturing stages and associated perforations, the quantity and type of fracturing fluid and proppant to use, and geologic variability. These decisions are dependent on the subsurface parameters at each development due to the heterogeneities of rock and fluid properties as well as the nearby historical development. Such complex and dynamic problems combined with the fast pace and large scale of unconventional development pose a significant challenge for classical physics-based reservoir models. We propose a data-driven modeling methodology that is used to support development decisions in the STACK play in Oklahoma.
We utilize multi-variate analytics to model the behaviors of horizontal wells in the STACK (Sooner-Trend-Anadarko-Canadian-Kingfisher) of the Anadarko basin (see Fig. 1 for idealized geologic cross section). The STACK consists of two primary targets, the Meramec shale and the Woodford shale. The Mississippian age Meramec is 200-500’ thick with porosity ranging from 3-6%.The Mississippian/Devonian age Woodford ranges from 75-300’ thick with 3-7% porosity. The Meramec formation consists of several parasequences of fine-grained silts with significant carbonate input in some intervals. Our analysis includes over 500 horizontal wells that target the core intervals in the Meramec. We use these wells in our workflow that predict their production performance impact with respect to both the location of horizontal wells in the STACK trend and multiple engineering variables.
In unconventional resource plays, wells drilled and completed in the same area, within the same target and with the same completions can have results that vary by +/− 50% vs the mean. Without a predictive model to explain this variance, production variability looks like random noise. We chose to use a simple statistical technique called a hypothesis test, and interpret the result using a p-value, a measure of statistical significance. Using the p-value, a trend can be tested to see if the trend in a sample of data is statistically different than the trend that would be expected from a random sample. Several studies have been published on multivariate analytic workflows1,2,3,4.
The Late Devonian Duvernay Formation is a burgeoning shale reservoir within the Western Canada Sedimentary Basin (WCSB) that accumulated as an organic-rich basinal mudrock concurrent with shallow marine carbonates of the Leduc and Grosmont formations. The WCSB is partitioned into the West and East Shale Basins by a narrow, linear Leduc Formation reef complex known as the Rimbey-Meadowbrook trend. Since 2011, Duvernay exploration has been focused in the West Shale Basin. This study characterizes sedimentologic, stratigraphic and geomechanical controls on Duvernay reservoir potential across the East Shale Basin based upon detailed description of core from 42 wells. Ten basinal Duvernay depositional facies were identified, and nine sequence stratigraphic surfaces were correlated across the study area. Geologic attributes were mapped to identify fairways of shale deposition within the East Shale Basin.
The Western Canadian Sedimentary Basin (WCSB) of Alberta, Canada is a prolific hydrocarbon province that includes both conventional and unconventional reservoirs (Figure 1). The Upper Devonian Duvernay Shale serves as the source rock for most of the conventional hydrocarbon resources of the WCSB, and more recently (circa 2011) has been successfully targeted as an “unconventional” hydrocarbon reservoir. The Duvernay accumulated as an organically-enriched basinal mudrock during an episode of second-order maximum flooding, and is contemporaneous with shallow marine platform carbonates of the Leduc and Grosmont formations. The WCSB is partitioned into the West and East Shale Basins by the narrow and linear Leduc Formation reef complex known as the Rimbey-Meadowbrook Trend (Potma et al., 2001; Stoakes, 1980; Stoakes and Creaney, 1985). Within both the West and East basins, the Duvernay accumulated in dysoxic marine conditions, and the most organically-enriched Duvernay deposits occur in basinal settings farthest from the equivalent platform carbonates of the Leduc and Grosmont (Chow et al., 1995).
This study defines the sedimentologic and associated sequence stratigraphic controls on Duvernay rock properties and is based upon the detailed description and analysis of 42 continuously cored wells and their associated well logs, and well logs from an additional 216 wells. Four regional stratigraphic cross sections include high quality “modern” well logs and abundant core: two cross sections extend across the West Shale Basin (WSB) and two extend across the East Shale Basin (ESB) (Figure 1). Previous studies of the Duvernay Formation characterize its qualities as a source rock to most conventional reservoirs within the WCSB (Stoakes, 1980; Stoakes and Creaney, 1985; Weissenberger, 1994; Chow et al., 1995; Fowler et al., 2001; Potma et al., 2001; Passey et al., 1990; Passey et al., 2010; Rokosh et al., 2012) and more recently as a prolific shale reservoir within the WSB with development opportunities within the East Shale Basin (Preston et al., 2016; Etam, 2017; Bauman, 2018; Groberman et al., 2018; Currie, 2018; PrairieSky Royalty Ltd., 2019a, 2019b, and 2019c; Wong et al., 2016a; Young, 2019).
In self-sourced low-permeability reservoirs the efficiency at the interaction between the mudstone matrix and fractures is a key control on well performance. Commonly, the more heterogeneous (interbedded) the reservoir the more complex fracture network is naturally developed or can be achieved during stimulation. In this study, using observations from two different unconventional shale units, we demonstrate that mudstone stratigraphic heterogeneities are scale dependent, and thus capturing their expression at different scales is key to understanding the level to which facies arrangements can affect important petrophysical, geochemical and geomechanical properties. Characteristics from the Duvernay Formation in Alberta-Canada and the Woodford Shale in Oklahoma-USA were compared in this study; both units are Late Devonian in age and are organic-rich prolific reservoirs. Lithologies in the Duvernay mostly vary according to changes in carbonate content, whereas in the Woodford changes are according to quartz content. However, in both cases a systematic alternation of two distinct rock types is evident at the cm-scale in outcrops and cores: organic-rich and calcite-rich facies for the Duvernay, and mudstones and chert facies for the Woodford. By combining high-resolution geochemical and geomechanical data, two distinct trends were evident for both units, and illustrate that variations in organic contents, mineralogy and relative hardness can be grouped by the two main rock types for each unit. In the Duvernay, the calcite-rich facies occur as low-TOC beds, at the microscale these are dominated by pore-filling calcite cements. In the Woodford, chert beds present the lower TOC content and their microfabric consists of microcrystalline aggregates of biogenic/authigenic quartz. In both units, the higher porosity values correlate with the high-TOC beds with abundant interparticle porosity. As for mechanical hardness and natural fractures, the higher calcite and quartz contents positively correlate with stiffer beds which generally are more brittle and have more natural fractures. The interbedded character between high-TOC and low-TOC beds is common for both units but at different frequencies and thickness. Capturing the degree of interbedding using a heterogeneity index suggests that reservoir behavior might be depicted as a multi-layered model in which properties are affected by the thickness, permeability, storage capacity, stiffness and fracture frequency of each bed. Although sometimes neglected, the study of fine-scale variations in reservoir properties can provide significant criteria for the selection of optimal horizontal landing zones.
Determination of ideal horizontal targets for unconventional reservoirs often necessitates an understanding of the reservoir from the global tectonic to the sub-microscopic scale. When selecting a target zone, it is necessary to consider the abundance, composition, and delivery of sediment to basins; the production, preservation, and alteration of organic matter; and the diagenetic and structural modification of the stratigraphic section. Here, we focus on two sedimentologic phenomena common to the Marcellus Shale of the Appalachian Basin of southwestern Pennsylvania. Namely, we explore the strategy of targeting high organic carbon/biogenic silica facies and the challenges posed by encountering carbonate concretion horizons.
Geochemical observations including Si/Al and Si/Zr, and thin section and scanning electron microscopy indicate abundant recrystallized biogenic quartz cement in the Marcellus Shale. Burial models suggest that prior to the end of mechanical compaction; the Marcellus entered the oil window, and presumably began generating organic matter-hosted porosity at a depth of ~1200m. Notably, at similar organic carbon content, samples with elevated biogenic silica yield higher porosity and permeability. These observations suggest that biogenic quartz may play a role in the deliverability of hydrocarbons by providing a compaction resistant framework conducive to the preservation of organic matter-hosted pores and pore throats. Further, biogenic quartz-rich facies demonstrate increased rates of penetration allowing for more efficient drilling of laterals.
However, carbonate concretions encountered while drilling horizontal Marcellus Shale wells negatively affect drilling operations by reducing drilling rates, damaging bits, and requiring excessive steering corrections to penetrate or extricate the bit from the horizon. Carbonate concretions form by the anaerobic oxidation of methane in a narrow zone perhaps just a few meters below the seafloor. Crucial to this mechanism is a slowing or pause in sedimentation rate that would have held the zone of carbonate precipitation at a fixed depth long enough for concretions to grow. Using this model, we attempt to predict the size and location of concretions to avoid encountering them while drilling. Field observations of Upper Devonian shale-hosted concretion dimensions suggest that Marcellus-hosted concretions up to three feet in length are possible. Hiatuses in sedimentation and potential concretion horizons were predicted using uranium to organic carbon ratios. The attachment of uranium to organic carbon macerals occurs across the sediment-water interface. Therefore, an increase in the abundance of uranium per unit organic carbon indicates a cessation in sedimentation and the potential for concretion growth. Indeed, when comparing well log response to core, uranium to organic carbon excursions predicted the location of two concretion horizons.
The Mississippian section, in particular the Meramec and the Devonian Woodford continue to be the preferred investment targets in the SCOOP/STACK trend in Oklahoma We showcase here the seismic characterization of these formations using multicomponent seismic data in the STACK area and the conventional vertical component seismic data in the SCOOP area, using deterministic prestack impedance inversion. The joint impedance inversion carried out over seismic data from the STACK area was used to derive rock-physics parameters (Young's modulus and Poisson's ratio), which showed the sweet spots that are distinct spatially, rather than bleeding off at the edges. The added advantage of joint inversion was that the density attribute could also be derived therefrom, which was not possible for the data from the STACK area. In addition to density, the results from prestack joint impedance inversion have been found to be superior to the simultaneous inversion. The equivalent attributes (besides density) derived for the SCOOP area also show promise.
The Oklahoma SCOOP play extends about 200 miles along the east flank of the Anadarko Basin, and along with the STACK play, have become one of the most active unconventional plays in the US. The trend has gathered attention due to its potential for oil and liquids-rich gas yields, record-setting IP from wells, superior economics and proximity to pipelines and infrastructure. Consequently, oil companies are making huge investments in these plays.
SCOOP is an acronym for
Evans, Kaitlin (West Virginia University) | Toth, Randy (West Virginia University) | Ore, Tobi (West Virginia University) | Smith, Jarrett (West Virginia University) | Bannikova, Natalia (West Virginia University) | Carr, Tim (West Virginia University) | Ghahfarokhi, Payam (West Virginia University)
Data obtained from the Marcellus Shale Energy and Environment Laboratory (MSEEL) project was used to understand how pre-existing fractures behave under elevated pore pressure. 1680 pre-existing fractures were identified along the lateral of the MIP-3H well. Image logs and 3D computer tomography (CT) scan of the cores was used for fracture location and most fractures were identified as calcite-filled and resistive. In addition, sonic scanner well logs provided minimum horizontal stresses for every few feet, and the pilot-hole density log provided the vertical stress at each point along the lateral. This collection of geologic and geomechanical data helped us to establish an anisotropic stress field with separate stress tensors for each stage. Twenty-eight stress tensors were constructed corresponding to twenty-eight completion stages within the MIP-3H well. The vertical stress component of the tensors was calculated by integrating MIP-3 pilot-hole density log to the average depth of each stage. The minimum horizontal stresses (Shmin) were also calculated by averaging the recorded Shmin readings in each stage. Maximum horizontal stress (Shmax) was calculated by a third-party logging vendor by adding a 400 psi to the Shmin values. The stress tensors were transformed into a geographic coordinate system along with the dip and strike of each fracture. The transformed coordinate system (North-East-Down) was used when applying Cauchy's Stress theorem to every singular fracture within each stage to calculate the normal and shear stress components on each fracture. A Mohr diagram was created for each stage with two failure criteria lines corresponding to mu (μ) values of 0.6 and 1.0. Fractures are displayed on the diagram using their calculated normal and shear stresses. The pore pressure increase found from the average treatment pressure for each stage was applied and whether natural fractures experienced tensile or shear failure was inspected. The objective is to understand if natural fractures experience shear failure or tensile failure during hydraulic fracturing and determine if there is a contrast in the response between resistive (calcite-filled) and conductive fractures. It was observed that prior to hydraulic fracturing, resistive natural fractures are mechanically dead and are in the stable region of the Mohr diagrams. Results show that although the majority of the pre-existing fractures are identified as resistive and mineral-filled, they undergo tensile failure when pore pressure was increased during hydraulic fracturing.
Recent technological progress within the petroleum industry has enabled much deeper discoveries than conventionally accepted depths. One example of such exploration success is drilling and stimulating an appraisal well in a Devonian age carbonate reservoir in northwestern Kazakhstan.
This paper describes a successful case study of hydraulic fracturing stimulation as a solution to enhance hydrocarbon recovery. A specific workflow developed for stimulation of high pressure and temperature low permeability reservoir is suggested. This workflow includes an adapted study of petrophysical properties, fracture geometry modeling, and completion design selection. Fracture stimulations and pre- and post-completion results are also analyzed and compared.
One of the main tasks of the technical staff was designing a production enhancement method which would maintain positive return on investment (ROI) for the project. A reservoir study was conducted during the planning stage of this pilot project. The design workflow included geomechanical analysis to estimate reservoir rock properties. Fracture stimulation modeling was performed to forecast treating pressures and adjust treatment stage sizes to help achieve optimum fracture geometries. Perforation intervals were selected and recommended to provide the best placement of fracturing fluid and proppant into the zone of interest.
Previously, the operator had attempted an acid wash, which was unsuccessful because of coiled tubing (CT) capability limitations, making it impossible to inject acid in desired rates into the rock due to low permeabilities and high stresses. Then, based on the final designed stimulation treatment plan, the operator conducted a massive proppant and acid fracturing stimulation operation, where high pressure pumping was performed at the treating pressures above formation breakdown limits. Created hydraulic fractures provided conductive pathways for reservoir fluid inflow. This method has shown an improved recovery of reservoir fluid. This hydraulic fracturing technique provided economically effective field exploration in the previously undeveloped part of the licensed block.
Field execution has shown challenges with respect to performing operations in deviated wells. Observations conducted in three stages during the pilot project are described and conclusions presented. This paper also describes operational difficulties with equipment combined with materials logistics.
Teklu, Tadesse Weldu (Colorado School of Mines) | Park, Daejin (Korea Gas Corporation and Colorado School of Mines) | Jung, Hoiseok (Korea Gas Corporation and Colorado School of Mines) | Amini, Kaveh (Colorado School of Mines) | Abass, Hazim (Halliburton and Colorado School of Mines)
Tadesse Weldu Teklu, Colorado School of Mines; Daejin Park and Hoiseok Jung, Korea Gas Corporation, and Colorado School of Mines; Kaveh Amini, Colorado School of Mines; and Hazim Abass, Halliburton and Colorado School of Mines Summary Matrix and fracture permeability of carbonate-rich tight cores from Horn River Basin, Muskwa, Otter Park, and Evie Shale formations, were measured before and after exposing the core samples to spontaneous imbibition using dilute acid [1-or 3-wt% hydrochloric acid (HCl) diluted in 10-wt% potassium chloride (KCl) brine]. Permeability and porosity were measured at net stress between 1,000 and 5,000 psia. Brine and dilute-acid imbibition effect on proppant embedment, rock softening/weakening, and fracture roughness were assessed. The following are some of the experiment observations: (a) Formation damage caused by water blockage of water-wet shales can be improved by adding dilute HCl or by using hydrocarbon-based fracturing fluids; (b) matrix permeability of clay-rich or calcite-poor shale samples is usually impaired/damaged by dilute-acid imbibition; (c) matrix permeability and porosity of calcite-rich shales usually improved with dilute-acid imbibition; (d) effective fracture permeability of unpropped calcite-rich shales is reduced by dilute-acid imbibition; the latter is because of "rock softening" and "etching/smoothing" of fracture roughness on the "fracture faces." Nevertheless, dilute-acid imbibition is less damaging than brine (slickwater) imbibition; and (e) proppant embedment was observed during both brine (slickwater) and diluteacid imbibition. Introduction A statistical report in EIA (2016) shows that, in the United States, oil and gas production from tight formations have become increasingly significant since 2007. This is mainly because of the advancement of multistage hydraulic-fracture stimulation in horizontal wells. Even with multistage hydraulic-fracture stimulation horizontal-well technology, oil recovery from tight formations such as the Bakken is usually less than 10% (Alharthy et al. 2015; Sheng 2015; Teklu et al. 2017a). Hence, many researchers are devoted to improving this low oil recovery. Enhanced-oil-recovery studies in tight formations through surfactant and gas injection and acid treatment are among the recent research directions toward improving the ultimate recovery of tight formations or shales (Teklu et al. 2017a, 2018).
Unconventional reservoirs, especially shale gas reservoirs, exhibit dual porosity (free fluid porosity and adsorbed fluid porosity). The adsorbed volume is a function of total organic carbon (TOC) and thus, higher organic contents are assumed to be directly related to higher hydrocarbons in place. However, this case study tried to evaluate this concept and found that with higher TOC, though gas in place increases the recoverable hydrocarbons reduces due to the low contribution from adsorbed heavier components.
We thoroughly evaluate the impact of organic contents on adsorbed hydrocarbons and further compare with the petrophysical properties and production behaviors; herein using information from the Devonian aged Duvernay Formation in Western Canada. First, multi-well analysis of core and log-derived TOC revealed that variations in organic contents are a function of the stratigraphy and thermal maturity, particularly increases in carbonate contents seems to correlate with lower organic contents, whereas increases in quartz and clays correlate with higher organic contents. Then, adsorption capacities were analyzed as a function of variations in the TOC. Finally, comparisons of hydrocarbons in-place and production contribution of the adsorbed volume is analyzed for different average TOC wells.
It is observed that TOC impacts relative adsorption of methane which further impacts the fluid characteristics (gas wells have higher average TOC as compared to the oil wells). This observation becomes relevant as we could partially understand well performance from fundamental understandings of the variations in organic contents. Results of Langmuir isotherms indicate a significant increase in adsorption of heavier components compared to the increment in adsorption of methane components with higher TOC. This observation is further analyzed for production data of the multi-fractured horizontal wells which suggested the following: 1) desorption in the oil flowing wells increases as the saturation of the oil phase decreases, or in other words when the relative permeability of the gas increases. 2) In the gas flowing wells, desorption does not follow the trend of the relative permeability, while based on Langmuir pressure initial contribution is significant which declines as reservoir pressure drops. Further, for the gas flowing well, the production forecast from calibrated production model (with measured produced volumes) shows that post-production of 10 years, recovery is 3.66% in which contribution from desorption is about 17.6%. This observation in the production analyses highlights how with different adsorption capacities of heavier components, adsorption contribution in the production varies. Finally, post this study it is found that TOC plays a vital role in adsorption capacity, gas in place and in the production performance. The relation of the TOC with fluid characterization and recoverable reserves is complex and should be analyzed with the variation in adsorption and desorption capacity of lighter and heavier components.
The present paper describes the results of analysis of depositional environment and tectonic setting within Karaton-Tengiz uplift zone in the southeastern part of the Pre-Caspian basin. The main purpose of the study is generalization and interpretation of geological and geophysical data for creation of stratigraphic charts and a description of lithological and tectonic processes for reconstruction of the structural history of pre-salt prospective traps located close to Tengiz field.
It is known that carbonates are "born, not made"; hence, their characteristics can give an insight into their depositional environment. The combination of such factors as availability of the light, warm climate, chemical composition and transparency of the water define the growth of the reef-building organisms. The highest carbonate production takes place close to the water surface; therefore, facies and texture of carbonates may be linked to the sea level changes. This means that understanding of the depositional environment and sequence stratigraphy may be used for a potential reservoir description where no well data is available. As a general understanding of the relative sea level fluctuations and its effect on carbonate growth, comparison of vertical thickness of studied platforms was carried out.
Analysis of regional seismic reflectors P3 (Top of Middle Devonian, tentative), P2D (Top of Upper Devonian), P2 (Top of Carboniferous), P1 (Top of Permian), VI (Kungurian salt deposits), V (surface of unconformity, Triassic), III (Top of Jurassic), II (Top of Lower Cretaceous) was also carried out for understanding of tectonic processes. Dipping of reflectors, thickness and depth variation of time-equivalent units, unconformities may indicate the change in tectonic setting. The shallowest depth of top of carbonates is observed on Tazhigali-Pustynnaya structure, gradually deepening towards Ansagan and Maksat to the south-southeast. Also, post-salt III and V reflective horizons are inclined from the north to the south of Karaton-Tengiz uplift zone.
Tectonic deepening in the south-southeast direction took place in several stages. The first stage, most probably, took place in Late Devonian–Early Carboniferous, as the result of which Ansagan and Maksat structures drowned. In the northern part of the Karaton-Tengiz uplift, the growth of reefs continued up to Late Carboniferous.
Well logging interpretation and published papers were integrated when possible. As the result, a conceptual model of the geological history and stratigraphic charts were created for the studied region.