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.
As unconventional plays in North America mature, understanding the performance of step-out and infill wells becomes increasingly important. “Child” well performance has become a major topic of interest because in every unconventional play there exists a significant portion of child wells that perform worse than their “Parents”. It is important to understand how child wells are likely to perform across a play so that engineers can properly forecast production and organizations can allocate capital correctly. The objective of this study was to establish an efficient scoping workflow for understanding the effect of depletion on child well performance across an area of interest, so that promising infill locations can be recognized, and risky infill locations avoided.
The problem with the current parent-child paradigm is that it requires explicitly defining what constitutes a parent, or conversely a child. As described in this study, the choice of definition immediately introduces bias into the interpretation of child performance. A simple function was developed to express the parent child relationship as a continuum, where the influence of parents on a given reference well decays with distance. A workflow was then established to apply the function across a large public well dataset. The workflow handles stacked development, accommodates large scale geological variation and can be efficiently applied over a significant number of wells.
The workflow was applied to areas of interest within the Montney formation in the Western Canada Sedimentary Basin. Results indicate that the depletion function can describe well performance in many areas of interest. Child performance heat maps were generated to identify potential opportunities for infill development. The workflow was also employed to detect performance outliers which could be further investigated to understand child well optimization.
Recent studies have indicated that a substantial percentage of wells “Children” in unconventional plays perform worse on a completion-normalized basis than their predecessors within a defined distance “Parents” (Lindsay et al. 2018). One of the main reasons cited for poorer than expected performance of Child wells is depletion (Cao et al. 2017, Lindsay et al. 2018, Shin and Popovich 2017). Depletion in the vicinity of the child well has the following effects:
In the Dunvegan Kaybob South Pool, recent multistage fracked horizontal wells have revealed the presence of a light oil play enveloping a large legacy gas field, developed with vertical wells. The boundary between the oil and gas producing areas intersect structural contours a high angle within deltaic sandstones of the Cretaceous Dunvegan Formation. To address controls on this boundary, a multidisciplinary study of cores, core analysis data, well logs was completed and integrated with test and production data to identify controls on fluid production.
Legacy gas production is from relatively high permeability delta front sandstones, while oil dominated production occurs from lower permeability, fine grained pro-delta deposits. While wells within the legacy gas field produce very low volumes of oil, core fluid extractions reveal significant oil is also present within this portion of the reservoir, but is not mobile. The Dunvegan clearly demonstrates permeability as the main control on the anomalous fluid distributions, with several other tight sandstone plays showing similar relationships, although often more subtle, such as observed in the Cardium, Montney, etc.
The anomalous fluid distributions with higher gas saturations in higher permeability beds and higher oil saturation in lower reservoir quality beds contradict conventional capillary reservoir charge models. Thus, we propose late stage migration of predominantly gas related to the increase in gas generation post peak oil window due to increasing maturity of the kerogen during burial. These late generated gas fluids migrated from the deeper part of the basin preferentially within higher permeability strata and fractures, and displace the earlier emplaced oil resulting in reservoirs with high GOR. These counterintuitive observations with higher liquids production from lower reservoir quality, can significantly improve the play economics and allow better prediction of fluid distribution in many plays.
Although unconventional low permeability reservoirs form laterally continuous thick hydrocarbon accumulations, they often have variable liquid saturations vertically and laterally. While varying kerogen type and maturity are important controls. In several plays, fluid distribution shows a strong correlation with permeability, with higher gas saturations occurring in more permeable beds. The control of permeability on anomalous fluid distribution has been discussed for several clastic, low permeability unconventional light oil and liquid rich gas plays in the Western Canada Sedimentary Basin (e.g. Wood and Sanei 2016, Venieri and Pedersen 2017). In this study we present a study of a legacy gas pool producing from deltaic sandstone reservoirs of the late Cretaceous Dunvegan Formation (Figure 1). The pool is located within the deep basin of western Alberta, an area of pervasive hydrocarbon saturation charged by enveloping thermal mature organic rich mudstones and coals (Masters 1984). The Dunvegan Kaybob South Pool is comprised of a lowstand delta lobe of the southward prograding Dunvegan Delta (Bhattacharya 1993).
For the vast majority of civilization, humans died in a world that looked very much like it did when they were born. But recently, the exponential growth of technology has fundamentally shifted the world's systems and the humans that occupy them. The oil and gas industry struggles with the question of how it will adopt and adapt in light of these technological advancements. A major driver in the current market uncertainty is choosing a technology that will provide optimal learning for the least amount of effort, money, and time.
In this paper, the benefit of using a technological advantage is explored from the point of view of generating type curves and forecasting well production. Traditional decline curve methods are founded on analytical expressions from the 1940s that are strictly based on empirical observations. Currently, engineers and analysts use a mix of these contemporaneous methods (and derivations thereof) and area expertise in their technical assessments to forecast well production. This type of analysis can introduce a level of bias which makes it very difficult, if not impossible, for two independently generated forecasts to be meaningfully reconciled against one another.
This two-part study explores a data-driven physio-statistical method for deriving production forecasts. The predictive analytical model underpinning this method has been trained on over 200,000 conventional and unconventional wells drilled in various plays with an extensive range of depositional environments, completion types, vintages, fluid properties, and operating conditions. Using solutions to differential equations to ensure that forecasts are generated honouring the fundamentals of fluid flow, provides accurate, unbiased, repeatable, and validated results.
This paper is based on work for a study area that encompasses 29 horizontal Montney gas wells in NE British Columbia. In part 1 of this study, production forecasts generated by the physio-statistical model (the Model) are compared to those generated by an experienced human reservoir engineer (HRE). The latter used a sophisticated commercially available decline curve analysis toolkit modified for unconventional reservoirs. Forecasted production volumes were compared against 12-months of actual production data and the suitability and limitations of the Model's forecasts are discussed.
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.
Venezuela possesses a world-class, hydrocarbon source rock from one of the most prolific places for oil accumulation in the world. This source rock, the La Luna Formation, (Cretaceous in age) is located in eastern Venezuela's Maracaibo Basin. Local variations in depositional and diagenetic conditions have manifestly affected the preservation and dilution of organic matter to some degree, generating small-scale variability in the depositional environments, and thus creating a higher-quality source rock within the depositional sequence that can be more prospective than others. To understand the variability of the depositional conditions, variations in organic matter source, thermal maturity, depositional environments and the use of organic/inorganic geochemical parameters were crucial in this study. This combined source rock evaluation composed of geological and geochemical parameters indicated an excellent potential as an unconventional reservoir for oil and gas in the study area. Geochemical analysis (Pristane, phytane (Pr/Ph), distributions of regular steranes, hopanes, monoaromatic steroid hydrocarbons (MAS) and tentative identification of gammacerane) confirmed the excellent quality of the organo-facies with higher productivity and preservation. Thermal maturity parameters indicate that most of the studied cores are within the oil window. Liquid hydrocarbons in the study area occur in the northwest and southwest areas, and condensates and dry/wet gases occur in the northeast. The lithofacies association, the sequence-stratigraphic framework, relative hydrocarbon potential (RHP), and biomarker analysis identified the depositional environment as an epicontinental sea developed in a shallow marine, upper shelf euxinic environment represented by a series of third order sequences of Highstand and Transgressive System Tracts overlying the erosional top of the underlying Cogollo Group. These stark differences show the tremendous value that biomarkers provide in the exploration of prospective source rocks. Not only do they help to identify paleoenvironmental changes and redox conditions, but they also depict the best organo-facies and accurate maturity parameters of the rock.
The geochemical and petrophysical complexity of source-reservoirs in Liquid-Rich Unconventional plays (LRU) urges for the implementation of alternative analytical protocols for initial play assessment. In this study, samples from selected source-reservoirs in the USA and the UK were analyzed by high frequency-nuclear magnetic resonance (HF-NMR relaxometry), followed by hydrous pyrolysis, and modified Rock-Eval pyrolysis methods (multi-heating rate methods, MHR). The analytical protocol here presented attempts to better qualify and quantify different petroleum fractions (mobile, heavy hydrocarbons, viscous, solid bitumen), and thus provide valuable and refined information about producibility of target intervals during appraisal stages.
Modified Rock-Eval Pyrolysis (MHR). Briefly, the pyrolysis oven program had four temperature ramps (at 50 °C/min) and isothermal plateaus (maintained isothermal for 15 minutes) at 200°C, 250°C, 300°C and 350°C, with a fifth and last ramp of 25°C/minute to 650°C. HF-NMR Relaxometry Hydrogen NMR measurements were made with a special 22MHz spectrometer from MR Cores equipped with a 30-mm diameter probe. The T2 data were acquired using the CPMG sequence with an echo time spacing of TE=0.07 ms. The T1 data were acquired using an inversion-recovery sequence. Selected samples (Kimmeridge Clay, Green River Shale) were subjected to hydrous pyrolysis experiments. Crushed rock chips (2-4 g, 1-3mm top size) were loaded into mini-reactor vessels (25-35 mL internal volumes). Rock chips were covered with deionized water and the reactor was placed in a gas chromatograph oven at the chosen temperature, generally for 72h.
Initial results show how the hydrocarbon fractions interpreted from NMR regions are in good agreement with those from MHR pyrolysis analysis in terms of hydrocarbon mobility/producibility. Results from hydrous pyrolysis experiments show that an exception to this general agreement between NMR and MHR estimates occurs for the Kimmeridge Clay samples, where MHR shows an increase of > 90% in producible hydrocarbon yields vs. minimal to no presence of mobile hydrocarbons in NMR T1-T2 maps. Ongoing experiments will clarify the role of pore structure and networks in these discrepancies of producible oil estimates when comparing pyrolysis with NMR-based techniques. This multi-step, multidisciplinary approach provides an opportunity to use it as a screening analysis to identify zones of higher OIP and predict fluids mobility prior to drilling. The novelty of our study is the integration of laboratory-derived analytical data (HF H-NMR, MHR and Hydrous Pyrolysis, organic petrography) to assess the proportion of the OIP that is producible prior to drilling or completions.
Kiani, Mojtaba (Nalco Champion, An Ecolab Company) | Hsu, Tzu-Ping (Nalco Champion, An Ecolab Company) | Roostapour, Alireza (Nalco Champion, An Ecolab Company) | Kazempour, Mahdi (Nalco Champion, An Ecolab Company) | Tudor, Eric (Nalco Champion, An Ecolab Company)
Fast production decline in Saskatchewan's tight oil assets has left behind billions of barrels of oil. In the past few years, waterflooding has been utilized to reduce the production decline rate to some extent, however, further optimization in waterflood performance is desired by operators. In this paper, we present our methodology to enhance waterflooding in Saskatchewan's Bakken field, reducing the rate of production decline. This methodology relies upon surfactant-based production enhancement formulations specifically designed to boost waterflood performance. Laboratory experiments and field design are presented to support the assertion that waterflood performance can be enhanced. This approach is one of the earliest of its kind that systematically utilizes the surfactant to enhance water floods in Saskatchewan's assets.
In this paper, we cover the laboratory formulations, fluid-fluid and rock-fluid tests, and the pilot design process. Laboratory work includes formulation development and screening through stability, interfacial tension (IFT) measurement, emulsion tendency and imbibition tests to evaluate the rate of oil recovery against current waterflood. A correlation between IFT and oil recovery was observed and is also discussed. Using a spontaneous imbibition test and our optimized formulations resulted in an additional 35% of original oil in place (OOIP) recovery at 1000 ppm concentration compared to the 20% OOIP oil recovery when placed in brine only. As a result, wettability alteration and IFT reduction were identified as mechanisms that are effective at enhancing incremental oil recovery beyond the secondary brine mode.
After promising laboratory observations, a pilot design area was selected in Saskatchewan. Through a detailed analysis of well communications, breakthroughs, cumulative injection and production volumes, numerical simulation, and economics, a slug size of surfactant solution was proposed. It was identified that our designed treatment could be ineffective to some well patterns with strong frac communications and very short breakthrough times; however, a conformance treatment has been designed for these specific areas. The preliminary laboratory work and design work support the requirements to proceed to the next step of a pilot.
Successful results using this approach demonstrate the potential to increase the amount of recoverable resources in tight oil plays under waterflood.