The objective of the project is to reconcile and quantify the impact of geological and completion variables that cause significant EUR differences in two recent wells drilled and completed in the Uteland Butte member of the Green River formation in Uinta Basin, Utah. While the geology and reservoir conditions are similar for both wells, the completion design and parameters are different (Ball-and-Sleeve vs. Plug-and-Perf, job size, treatment rates, well length, etc.).
The Asset Team uses a structured workflow consisting of several modeling tools: Rate-Transient-Analysis (RTA), Frac Modeling (FM) and Reservoir Simulation (RS) to address and quantify the impact of each variable: Job size, Treatment Rate, Frac count per Stage, Well Length and the effect of clays.
The workflow began with a performance evaluation of the high EUR well (Plug-and-Perf, large job) with RTA and Frac modeling; followed by history-match and prediction of the EUR with the RS model. In the subsequent workflow, a single variable is changed in each modeling step, while others are held constant -- as such, the EUR impact for each variable can be quantified. The result from each step is calibrated with the actual performance observed in the field.
This model-based approach successfully quantified the production impact of each variable. Subsequently, the key drivers can be determined which explains the estimated EUR difference between the two wells. This work drives us to conclude that due to varying pressure, PVT and lithology across the field, different completion designs shall be utilized. The team has gained valuable insight on how to implement different completion techniques with varying job size and design for the basin. Currently, these results are used to drive the well designs and approval; with the long-term objective of optimizing the Field Development Plan.
Martini, Brigette (Corescan Inc.) | Bellian, Jerome (Whiting Petroleum Corporation) | Katz, David (Encana Corporation) | Fonteneau, Lionel (Corescan Pty Ltd) | Carey, Ronell (Corescan Pty Ltd) | Guisinger, Mary (Whiting Petroleum Corporation) | Nordeng, Stephan H. (University of North Dakota)
Hyperspectral core imaging studies of the Bakken-Three Forks formations over the past four years has revealed non-destructive, high resolution, spatially relevant insight into mineralogy, both primary and diagenetically altered that can be applied to reservoir characterization. While ‘big’ data like co-acquired hyperspectral imagery, digital photography and laser profiles can be challenging to analyze, synthesize, scale, visualize and store, their value in providing mineralogical information, structural variables and visual context at scales that lie between (and ultimately link) nano and reservoir-scale measurements of the Bakken-Three Forks system, is unique.
Simultaneous, co-acquired hyperspectral core imaging data (at 500 μm spatial resolution), digital color photography (at 50 μm spatial resolution) and laser profiles (at 20 μm spatial and 7 μm vertical resolution), were acquired over 24 wells for a total of 2,870 ft. of core, seven wells of which targeted the Bakken-Three Forks formations. These Bakken-Three Forks data (~5.5 TB) represent roughly 175,000,000 pixels of spatially referenced mineralogical data. Measurements were performed at a mobile Corescan HCI-3 laboratory based in Denver, CO, while spectral and spatial analysis of the data was completed using proprietary in-house spectral software, offsite in Perth, WA, Australia. Synthesis of the spectral-based mineral maps and laser-based structural data, with ancillary data (including Qemscan, XRD and various downhole geophysical surveys) were completed in several software and modelling platforms.
The resulting spatial context of this hyperspectral imaging-based mineralogy and assemblages are particularly compelling, both in small scale micro-distribution as well as borehole scale mineralogical distributions related to both primary lithology and secondary alteration. These studies also present some of the first successful measurement and derivation of lithology from hyperspectral data. Relationships between hyperspectral-derived mineralogy and oil concentrations are presented as are separately derived structural variables. The relationship between hyperspectral-based mineralogy to micro-scale reservoir characteristics (including those derived from Qemscan) were studied, as were relationships to larger-scale downhole geophysical data (resulting in compelling correlations between variables of resistivity and hyperspectral-mineralogy). Finally, basic Net-to-Gross calculations were completed using the hyperspectral imaging data, thereby extending the use of such data from geological characterizations through to resource estimations.
The high-fidelity mineralogical maps afforded by hyperspectral core imaging have not only provided new geological insight into the Bakken-Three Forks formations, but ultimately provide improved well completion designs in those formations, as well as a framework for applying the technology to other important unconventional reservoir formations in exploration and development. The semi-automated nature of the technology also ushers in the ability to consistently and accurately log mineralogy from multiple wells and fields globally, allowing for advanced comparative analysis.
Poor reproducibility of published findings is a problem that is plaguing most scientific fields. Low statistical power, insufficient sample size, and poor experimental design are often cited as contributing factors to irreproducibility. The majority of scientific research in the oil and gas industry is not designed to readily validate the hypothesis being generated. In a typical study, data is collected without an explicit expectation and the results are analyzed. In these cases, the outcome becomes known and hypotheses are derived afterwards with the benefit of hindsight. Though this process is valuable in scientific induction and hypothesis generation, it leaves most published “conclusions” without true validation. Additionally, due to the well-documented effects of “hindsight bias”, it is difficult to accurately gauge the success of a hypothesis when the results are already known. To truly demonstrate the veracity of the hypothesis, then, it is necessary to predict future behavior and validate these blind predictions with an adequate sample set. This study provides an example of blind validation using a multi-variate regression in the Midland Basin.
Using wells with known outcomes of oil performance, a hypothesis was generated to explain cumulative oil production in the form of a multiple linear equation. This hypothesis was then tested by generating blind predictions of well performance for the next 100+ wells - before they were drilled. Now, with the collection of significant production history on this well set, the accuracy of the blind predictions has been evaluated.
The findings suggest that 1) a relatively large sample set is required for validation 2) it is possible to blindly predict well performance more accurately than chance or stationarity and 3) withholding data during the model tuning process overestimates the success of the model when compared to blind, forward predictions.
The novelty of this study is in the collection of a blind sample set of newly drilled wells after the predictions were generated. This allows for the quantification of the model's predictivity loss when used in a truly forward sense. The significance of this observation is that the error found in a forward sense is not the same as is found when simply withholding a portion of the data for testing. The application of this learning is far-reaching. The majority of published models are validated in a backwards sense, using existing observations. However, most of these studies are aimed at predicting and manipulating future behavior, for example, improving well performance through completions design. Without taking the next step to prove that this future expectation was achieved with a significant sample set, it cannot necessarily be expected that a model will be useful for its intended application.
Petroleum produced from low permeability shales is different to the dispersed in-situ fluids from which it is derived. Whereas in-situ fluids consist of hydrocarbons, resins and asphaltenes in proportions governed by organic matter type, maturity and retention behaviour, the produced fluids are highly enriched in hydrocarbons and low polarity non-hydrocarbons, and show an enhanced GOR. Here, we study the effects of fractionation during production from Permian and Cretaceous shales using laboratory experiments, PVT-modeling and a regional PVT database. Our goal was to develop methodologies for predicting yields and compositions of produced fluids ahead of drilling.
Target wells with known fluid properties were used for calibration. Shales from neighbouring wells of slightly lower maturity were mildly matured to that of the calibration well using MSSV pyrolysis, and a PhaseSnapShot of the resultant fluid made using PVTsim.
The first example, from the late oil window Eagle Ford, demonstrates that both kerogen and bitumen are important petroleum precursors, and that in-situ compositions are largely determined by the most recently generated charge, rather than by cumulative addition during maturation. The PVT model, calibrated to the engineering report of the target well and its environs, reveals that a high proportion of the in-place C7+ fluids remain in the rock matrix relative to gas during production. The second example, taken from a gas and condensate fairway in the Permian Basin, shows that the predicted bulk composition of recently generated petroleum is facies dependent. PVT fluid calibrations have low Psat and low cricondentherms. These characteristics are reproduced by experiment, but only for those zones containing low contents of high molecular weight liquids. Any contributions to produced fluids from other zones is associated with massive retention of high molecular weight organics. The third example concerns volatile oil production from wells in the Permian Basin. The MSSV products generated by adjacent lower maturity shales exhibited phase envelopes with higher cricondentherms than that of the calibration, this being attributable to a molecular weight difference in heavy components. Adjusting the MW from 249 (measured) to 222 (produced oil PVT value) in the PVTsim model aligned the cricondentherms. This tuning step corresponds to the preferential retention of heavy polar compounds in the rock matrix during production. In a second step, 20% of the tuned MSSV-generated liquids are considered to be retained in the rock, thereby raising Psat. The result is an excellent match between the doubly tuned predicted phase envelope and that of the produced fluid. The preferential retention of polar compounds is also in line with this tuning step.
In summary, fractionation is part and parcel of production from shales. Up to 80% liquids retention relative to gas has been demonstrated. Production efficiency assessments are readily inferred from these data.
The extent to which fractionation occurs varies a lot, and has here been assessed by combining experimental rock geochemistry with PVT modeling (PhaseSnapShots), and using PVT reports on produced fluids for calibration.
Recent studies have indicated that Huff-n-Puff (HNP) gas injection has the potential to recover an additional 30-70% oil from multi-fractured horizontal wells in shale reservoirs. Nonetheless, this technique is very sensitive to production constraints and is impacted by uncertainty related to measurement quality (particularly frequency and resolution), and lack of constraining data. In this paper, a Bayesian workflow is provided to optimize the HNP process under uncertainty using a Duvernay shale well as an example.
Compositional simulations are conducted which incorporate a tuned PVT model and a set of measured cyclic injection/compaction pressure-sensitive permeability data. Markov chain Monte Carlo (McMC) is used to estimate the posterior distributions of the model uncertain variables by matching the primary production data. The McMC process is accelerated by employing an accurate proxy model (kriging) which is updated using a highly adaptive sampling algorithm. Gaussian Processes are then used to optimize the HNP control variables by maximizing the lower confidence interval (μ-σ) of cumulative oil production (after 10 years) across a fixed ensemble of uncertain variables sampled from posterior distributions.
The uncertain variable space includes several parameters representing reservoir and fracture properties. The posterior distributions for some parameters, such as primary fracture permeability and effective half-length, are narrower, while wider distributions are obtained for other parameters. The results indicate that the impact of uncertain variables on HNP performance is nonlinear. Some uncertain variables (such as molecular diffusion) that do not show strong sensitivity during the primary production strongly impact gas injection HNP performance. The results of optimization under uncertainty confirm that the lower confidence interval of cumulative oil production can be maximized by an injection time of around 1.5 months, a production time of around 2.5 months, and very short soaking times. In addition, a maximum injection rate and a flowing bottomhole pressure around the bubble point are required to ensure maximum incremental recovery. Analysis of the objective function surface highlights some other sets of production constraints with competitive results. Finally, the optimal set of production constraints, in combination with an ensemble of uncertain variables, results in a median HNP cumulative oil production that is 30% greater than that for primary production.
The application of a Bayesian framework for optimizing the HNP performance in a real shale reservoir is introduced for the first time. This work provides practical guidelines for the efficient application of advanced machine learning techniques for optimization under uncertainty, resulting in better decision making.
Ghanizadeh, Amin (University of Calgary) | Clarkson, Chris R. (University of Calgary) | Song, Chengyao (University of Calgary) | Vahedian, Atena (University of Calgary) | DeBuhr, C. (University of Calgary) | Deglint, H. J. (University of Calgary) | Wood, J. M. (Encana Corporation)
A schematic of the liquid permeameter, which was designed and constructed in-house for the measurement of liquid permeability using steady-state and pulse-decay flow techniques, is provided in Figure 1. The liquid flow tests were performed under controlled axial/radial confining pressures in a biaxial core holder.
Ghanizadeh, A. (University of Calgary) | Clarkson, C. R. (University of Calgary) | Clarke, K. M. (University of Calgary) | Yang, Z. (University of Calgary) | Rashidi, B. (University of Calgary) | Vahedian, A. (University of Calgary) | Song, C. (University of Calgary) | DeBuhr, C. (University of Calgary) | Haghshenas, B. (University of Calgary) | Ardakani, O. H. (Geological Survey of Canada) | Sanei, H. (Aarhus University) | Royer, D. P. (Encana Corporation)
Hydrocarbon storage capacity of organic-rich shales depends upon porosity and surface area, whereas pore (throat) size distribution and pore (throat) network connectivity control permeability. The pores within organic matter (OM) of organic-rich shales develop during thermal maturation as different hydrocarbon phases are generated and expelled from the OM. Organic-rich shales can potentially retain a large proportion of the hydrocarbons generated during the diagenesis process. Commercial hydrocarbon production from liquid-rich shale reservoirs can be achieved using completion technologies such as multi-stage-fractured horizontal wells (MFHWs). However, the ability of industry to identify "sweet spots" along MFHWs is still hampered by insufficient understanding of the effect of type/content of entrained hydrocarbon/OM components on reservoir quality. The primary objective of the current study is therefore to investigate the impact of entrained hydrocarbon/OM on storage and transport properties of the organic-rich shales.
To accomplish this goal, a comprehensive suite of petrophysical analyses are performed on a diverse sample suite from the Duvernay Formation (a prolific Canadian shale oil reservoir) differing in organic matter content (2.8-5 wt.%; n = 5), before and after sequential pyrolysis by a revised Rock-Eval analysis (extended slow heating (ESH) Rock-Eval analysis;
Compared to the "as-received" state, porosity, permeability, modal pore size distribution and surface area increase with sequential pyrolysis stages, associated with expulsion and devolatilization of free light oil and fluid-like hydrocarbon residue (S2a; up to 380 °C). However, the change in petrophysical properties associated with the degradation of solid bitumen/residual carbon (S2b; up to 650 °C) is variable and unpredictable. The observed reduction in porosity/permeability values after the S2b stage are likely attributed to 1) occlusion of pore volume with solid bitumen/residual carbon degradation (i.e. coking) and/or 2) sample swelling due to water loss from lattice structure of clay minerals (i.e. illite) and 3) sample compaction as a result of OM removal from the rock matrix.
The present study is a continuation of previous works (
Akihisa, Kunio (Japan Oil, Gas and Metals National Corporation) | Knapp, Levi (Japan Oil, Gas and Metals National Corporation) | Uchida, Shinnosuke (Japan Oil, Gas and Metals National Corporation) | Shimokawara, Mai (Japan Oil, Gas and Metals National Corporation) | Akita, Yasuyuki (Japan Oil, Gas and Metals National Corporation) | Wood, James M. (Encana Corporation) | Ardakani, Omid Haeri (Natural Resources Canada - Geological Survey of Canada) | Sanei, Hamed (Natural Resources Canada - Geological Survey of Canada)
This study was carried out to investigate the relationship between rock properties and gas wetness, in order to better identify and characterize sweet spot areas. The study was conducted in two horizontal wells penetrating across a local CGR anomaly in the Montney Formation silty sand tight gas reservoir.
First, the relation between mud gas components and CGR distribution was surveyed to confirm the applicability of mud gas wetness as a proxy for CGR of initial production gas. Second, permeability indices of drill cuttings were analyzed by laboratory NMR measurements and the relationship of permeability to solid bitumen saturation was examined. In addition, MICP-derived properties and QEMSCAN mineralogy are discussed. The results were examined with respect to changes in mud gas wetness in the surveyed wells.
In the study area, a strong positive correlation was found between produced gas CGR and mud gas wetness ratio. Mud gas wetness was negatively correlated to cuttings permeability and permeability was negatively correlated to bitumen saturation, suggesting methane migration occurred along high permeability, low bitumen saturation pathways. Based on these observations, both mud gas wetness and cuttings permeability indices were confirmed to be effective for detecting liquids-rich areas in under-developed areas.
The liquid content of produced hydrocarbon gas (or condensate gas ratio, CGR) is an important factor for detecting sweet spot areas in tight gas reservoirs.
The Lower Triassic Montney Formation is currently a prolific gas producer in the Western Canadian Sedimentary Basin and is projected to continue as a major energy resource in the future. Gaseous hydrocarbons are said to be originally accumulated as oil and then thermally transformed to gas during further burial of the reservoir horizon (Sanei et al., 2013).
Previous studies demonstrate that the Montney rock samples have a dual-wettability pore network. Recovery of the oil retained in the small hydrophobic pores is a unique challenge. In this study, we apply dual-core imbibition (DCI) method on several Montney core plugs and introduce imbibition-recovery (IR) trio to investigate the recovery mechanisms in rocks with dual-wettability pore network. First, we evaluate the wetting affinity of five twin core-plugs from the Montney Formation by measuring spontaneous imbibition of reservoir oil and brine, and by measuring equilibrium contact angle. We place one plug of each pair in the oil and the other in the brine, and measure the weight change periodically. Second, we place the oil-saturated samples in the brine to visualize the expelled oil droplets and measure volume of the recovered oil. We comparatively analyze the spontaneous imbibition data from the first step and the recovery data of the second step in one imbibition-recovery trio (oil imbibition, brine imbibition, and imbibition oil recovery). The results of air-liquid contact angle and spontaneous imbibition on dry samples suggest that the affinity of the samples to oil is higher than that to brine, in an air-liquid system. However, the results of liquid-liquid contact angle and counter-current imbibition tests suggest that the affinity of the samples to water is higher than that to oil, in a liquid-liquid system. For each twin set, the oil recovery curve follows the trend of brine imbibition curve, and the final oil recovery is always less than the equilibrated water uptake of dry samples. This observation indicates that water can only access the hydrophilic part of the pore network initially saturated with oil. Finally, we introduce a porosity-based model to analyze oil-recovery data.
Recent studies show that the pore network of unconventional rocks, such as gas shales, generally consists of inorganic and organic parts. The organic part is strongly oil-wet and preferentially imbibes the oleic phase. In contrast, the inorganic part is usually hydrophilic and preferentially imbibes the aqueous phase. Conventional theories of relative permeability, which are based on uniform wettability, cannot be applied to determine phase permeability in unconventional rocks with dual-wettability behavior. The objective of this paper is to extend the previous theories to model relative permeability of dual-wettability systems in which oleic and aqueous phases can both act as wetting phases in hydrophobic and hydrophilic pore networks, respectively.
In the first part of the paper, we review and discuss the results of scanning electron microscopy (SEM), organic petrography, mercury injection capillary pressure (MICP), and comparative water/oil imbibition experiments conducted on several samples from the Triassic Montney tight gas siltstone play of the Western Canadian Sedimentary Basin. We also discuss various crossplots to understand the reasons behind the observed dual-wettability behavior, and to investigate the spatial distribution and morphology of hydrophilic and hydrophobic pores. In the second part, Purcell’s model (Purcell 1949) is extended to develop a conceptual model for relative permeability of gas and water in a dual-wettability system such as the Montney tight gas formation. Finally, the proposed model is compared with measured relative permeability data.
The results suggest that the submicron pores within solid bitumen/pyrobitumen are strongly water-repellant; therefore, they prefer gas over water under different saturation conditions. This part of the pore network is usually represented by a long tail at the lower end of the pore-throat-size distribution determined from MICP. The proposed relative permeability model describes single-phase flow of gas through the tail part, and two-phase flow of gas and water through the remaining bell-shaped part of the pore-throat-size distribution, which dominantly represents inorganic micropores. On the basis of our model, by increasing the fraction of water-repellant submicron pores, gas relative permeability decreases for a fixed water saturation. This decrease is ascribed to the reduction of the average size of flow conduits for the gas phase.