Guedez, Andreina (MetaRock Laboratories) | Mickelson, William (MetaRock Laboratories) | Aldin, Samuel (MetaRock Laboratories) | Gokaraju, Deepak (MetaRock Laboratories) | Mitra, Abhijit (MetaRock Laboratories) | Thombare, Akshay (MetaRock Laboratories) | Patterson, Robert (MetaRock Laboratories) | Aldin, Munir (MetaRock Laboratories)
Laboratory measurements of porosity and matrix permeability are essential for accurate petrophysical characterization to aid in optimized planning for field development. The core must be cleaned before any petrophysical properties, such as porosity and permeability, are measured. The goal of the cleaning process is to remove all hydrocarbons, water and any possible invasion of drilling fluid during the coring process. Multiple cleaning methods, including flow-through cleaning, centrifuge flushing and distillation/extraction using Dean-Stark or Soxhlet methods are used and have been proven to be effective methods in conventional core. However, for unconventional rocks with ultra-low permeability like shales, the above methods are ineffective and time consuming. The distillation/extraction cleaning process has potential to induce micro fractures and/or parting of the rock that affect the measurements. Moreover, some cleaning methods for tight rocks involve crushing the sample to make the process time efficient. The disadvantages with this method include destroying the pore structure and rock fabric, overestimation of permeability and the amount of removable fluids and the inability to measure permeability under stress.
In this paper, an alternative technique for removal of mobile fluids from intact plug samples for subsequent permeability measurement is explored. The method involves multiple cycles of pressurized CO2 driven extraction. Samples from low permeability formations were cleaned using the proposed method. CT scans, microscopic images and steady state permeability measurements were employed to ensure the samples selected for this study were free of any pre-existing fractures. The weights of the samples were monitored at the end of each cleaning cycle. The cleaning process was considered complete when the weights stabilized. Comparison of pre and post cleaning oil and water saturation measurements using Karl-Fischer, Pyrolysis, and NMR indicate a significant decrease in fluid saturations. Lastly, porosity of the samples also increased as a result of the cleaning process.
The technique introduced in this paper provides a means to more accurately measure the absolute matrix permeability of ultra-tight rock, improving the understanding of fundamental petrophysical properties.
Cronkwright, David (University of Calgary) | Ghanizadeh, Amin (University of Calgary) | DeBuhr, Chris (University of Calgary) | Song, Chengyao (University of Calgary) | Deglint, Hanford (University of Calgary) | Clarkson, Chris (University of Calgary) | Ardakani, Omid (Geological Survey of Canada)
This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Denver, Colorado, USA, 22-24 July 2019. The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted by the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk. The information herein does not necessarily reflect any position of URTeC. Any reproduction, distribution, or storage of any part of this paper by anyone other than the author without the written consent of URTeC is prohibited. Abstract Fluid distribution and fluid-rock interactions within the nano-/macro-porous pore network of tight oil reservoirs will affect both primary and enhanced oil recovery (EOR) processes. Focusing on selected samples obtained from the liquids-rich reservoirs within the Montney Formation (Canada), the primary objective of this work is to evaluate the impact of mineralogical composition on micro-scale fluid distribution at different saturation states: 1) "partially-preserved" and 2) after a series of core-flooding experiments using reservoir fluids (oil, brine) under "in-situ" stress conditions. Small rock chips (cm-sized), sub-sampled from "partially-preserved" (using dry ice) core plugs, were cryogenically frozen and analyzed using an environmental field emission scanning electron microscope (E-FESEM) equipped with X-ray mapping capability (EDS).
The East Duvernay shale basin is the newest addition to the list of prolific reservoirs in Western Canada. Over the last 3 years, horizontal drilling and multistage hydraulic fracturing have increased significantly. Because much of the play is still relatively new, much of the drilling has been limited to single wells or two wells per pad. Due to the low permeability of the matrix, hydraulic fracturing is required to unlock the full potential of the East Duvernay field. Because geomechanics is a critical factor in determining the effectiveness of hydraulic fracture propagation, we examined how varying the pore pressure profiles affects modeled in situ stresses, hydraulic fracture geometries, and overall field optimization.
The pore pressure varies across the East Duvernay shale basin with the depth of the reservoir and other geomechanical parameters. The stresses in the Ireton, Upper Duvernay, Lower Duvernay, and Cooking Lake reservoirs also varies from the West to the East shale basins. High-tier logging, core measurements, and field data were used to build a mechanical earth model, which is then input for hydraulic fracture simulations. Whole core images and image logs indicate the Duvernay to be a naturally fractured reservoir. Because pore pressure is a direct input into the interpretation for in situ stresses, we sensitized on seven pore pressure profiles through the Ireton, Upper and Lower Duvernay, and Cooking Lake reservoirs. Typical pumping design currently being implemented in the Upper Duvernay was used to determine hydraulic fracture geometry based on the various in situ stress profiles. Black oil PVT models were built to run numerical reservoir simulation production forecasts to understand the effect of variations in geomechanical properties on well production performance. The effect of the varying hydraulic fracture properties on well spacing was also investigated for the seven pore pressure profiles, by combining the complex hydraulic fracturing and reservoir simulation.
The results clearly indicated the need to better understand, quantify, and constrain the in situ stress profiles variations with changes in pore pressure models. Hydraulic fracture length is greater within the Upper Duvernay when a constant pore pressure is modeled in the Ireton, Duvernay and the Cooking Lake, which leads to an overestimation of production. If a normal pore pressure is modeled in the Ireton with overpressure in the Duvernay, the hydraulic fracture grows into the Ireton and gives a more realistic production forecast. When the modeled pore pressure is gradually ramped up from the Lower Ireton into the Duvernay, slightly greater fracture length is created in the Duvernay but not enough to make a huge difference in forecasted production. These varying results for the modeled hydraulic fracture geometries impact the optimum number of wells per section.
As more wells come on production and the economic viability of the play is proven, operators will drill more wells per section. Thoroughly understanding the variations in geomechanics across the formations above and below the Duvernay is important. This objective of this study was to drive the conversation about the data that need to be collected and tests that should be run to support the optimization of economic development of the play for years to come.
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.
A method has been developed for the analysis of pressure falloff data following a single-stage treatment in a multi-stage fracture stimulation. The basic premise is that the greater the permeability contacted by the fracture stimulation, the greater the rate of pressure falloff will be. This can be done with as little as 15 minutes of falloff data, but with a “zipper” style completion, the surface pressure falloff of a given fracture stage may be monitored for several hours for no incremental cost while an offset well on the same pad is being stimulated. The initial falloff data is collected well before fracture closure, so proppant is not yet a factor – the pressure decay is influenced by the total fracture system of that stage.
This analysis has been performed on approximately 30 wells, each with about 20 stages, including two wells equipped with fiber optic sensing. The pressure decay follows a straight line on a plot of pressure versus logarithm of time. The slope of that line is the decay exponent, and a large exponent is indicative of greater connected permeability or fracture complexity.
The development of this technique is in its early phases, but thus far a good correlation has been observed between the pressure decay exponent and microseismic activity, as well as between pressure decay and the Young's modulus of the rock being stimulated. In a multi-cluster “plug and perf” completion equipped with fiber optic cable, a positive correlation was observed with the number of clusters being treated. When the same hydraulic fracture stimulation was executed in similar rock types, very consistent results were obtained, suggesting a valid and repeatable relationship. The final validation of this technique will be possible when compared against production logging results.
The prospect of a low cost, or even free, analytical technique in an environment where anything beyond a gamma ray curve is often a luxury, is particularly exciting. This assessment technique could be used for optimization of perforation cluster design and location, landing zone, and fracturing fluid optimization. The authors invite other operators to try this technique and discuss their observations.
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.
Penghui, Su (PetroChina Research Institute of Petroleum Explorationand and Development) | Zhaohui, Xia (PetroChina Research Institute of Petroleum Explorationand and Development) | Ping, Wang (PetroChina Research Institute of Petroleum Explorationand and Development) | Liangchao, Qu (PetroChina Research Institute of Petroleum Explorationand and Development) | xiangwen, Kong (PetroChina Research Institute of Petroleum Explorationand and Development) | Wenguang, Zhao (PetroChina Research Institute of Petroleum Explorationand and Development)
Interest has spread to potential unconventional shale reservoirs in the last decades, and they have become an increasingly important source of hydrocarbon. Importantly, pore structure of shale has considerable effects on the storage, seepage and output of the fluids in shale reservoirs so that reliable fractal characteristics are essential. To better understand the evolution characteristics of pore structure for a shale gas condensate reservoir and their influence on liquid hydrocarbon occurrences and reservoir physical properties, we conducted high-pressure mercury intrusion tests (HPMIs), field emission scanning electron microscopies (FESEM), total organic carbon (TOC), Rock-Eval pyrolysis and saturation measurements on samples from the Duvernay formation. Furthermore, the fractal theory is applied to calculate the fractal dimension of the capillary pressure curves, and three fractal dimensions D1, D2 and D3 are obtained. The relationships among the characteristics of the Duvernay shale (TOC, organic matter maturity, fluid saturation), the pore structure parameters (permeability, porosity, median pore size), and the fractal dimensions were investigated.
The results show that the fractal dimension D1 ranges from 2.44 to 2.85, D2 ranges from 2.09 to 2.15 and D3 ranges from 2.35 to 2.48. D2 and D3 have a good positive correlation. The pore system studied mainly consists of organic pores and microfractures, with the percentage of micropores being 50.38%. TOC has a positive relationship with porosity and D3 due to the development of organic pores. D3 has a positive correlation with gas saturation. With increased D3, median pore size shows a decreasing trend and an increase in permeability and porosity, demonstrating that D3 has a large effect on pore size distribution and the heterogeneity of pore size. In general, D3 has a better correlation with petrophysical and petrochemical parameters. Fractal theory can be applied to better understand the pore evolution, pore size distribution and fluid storage capacity of shale reservoirs.
Achieving high hydrocarbon recovery is challenging in unconventional tight and shale reservoirs. Although EOR/EGR processes could potentially improve the recovery factor beyond the primary depletion, large-scale field application of these processes are not yet established in these reservoirs. This session will focus on the latest research trends, modelling and experimental work to better understand issues involved in improved economic recovery from such reservoirs.