Ugueto, Gustavo (Shell Exploration and Production) | Huckabee, Paul (Shell Exploration and Production) | Wojtaszek, Magdalena (Shell Global Solutions International) | Daredia, Talib (Shell Canada Limited) | Reynolds, Alan (Shell Exploration and Production)
It has been widely demonstrated that frac stimulation efficiency and more importantly production, varies significantly between perforation clusters as well as between sleeve entries. Recent trends indicate that many operators are simultaneously increasing the number of perforation clusters or entries while decreasing frac-to-frac spacing. This is done with the expectation that it will lead to more productive wells overall. The purpose of this paper is to investigate some of the aspects that may limit this approach. There are an increasing number of frac diagnostic tools which allow us to get a better understanding of frac placement and production. Unfortunately, there are only few diagnostic tools available today to characterize the near wellbore region (NWR). Fiber Optics (FO) and other downhole measurements can play an important role in providing information about the NWR. In this paper, we share data and examples from wells where the combination of data from Distributed Acoustics Sensing (DAS), Distributed Temperature Sensing (DTS) and downhole gauges is helping us gain insights about this poorly understood region of our unconventional reservoirs. This paper combines DAS, DTS and downhole pressure gauge data to demonstrate the existence of significant near wellbore complexity, both during stimulation and production. We frequently observe changes in DAS signal and pressure during the stimulation of horizontal wells completed via both "Plug and Perf" (PnP) and Cemented Single Point Entry (CSPE) systems. These changes support the existence of significant near-wellbore tortuosity. Furthermore, we show that pressure data from downhole gauges can differ significantly from surface pressure data extrapolated downhole. This can impact the interpretation of Step-Down-Tests, other analytical techniques relying on the surface pressure alone and affecting the calibration of frac models aimed at understanding the NWR. In wells instrumented with a FO cable behind casing, it is possible to use the DTS data during warmback, following stimulation injection to gain insights about frac geometry in the NWR. Such data provides information about the hydraulic frac dimensions created by the stimulation process in both vertical and horizontal wells. During warmback it is easy to distinguish intervals containing hydraulic fractures near the wellbore where the temperature recovery is lagging compared to the unstimulated portions of the well. FO instrumented horizontal wells allow for estimation of the dimensions of the "Frac-Zone" along the wellbore in the NWR where a combination of hydraulically induced longiditunal and vertical transverse fracs exist. Thermal modeling is also presented for selected stages that further support the qualitative interpretation of the DTS. The diagnostics presented help quantify the dimensions of longitudinal and transverse components in horizontal wellbores in the NWR. This paper also highlights the risk of putting perforation clusters or sleeve entries too close to one another. It is clear that the NWR is poorly understood and more information is needed. Understanding the processes that govern the NWR are essential, after all, this is the region where the well and the reservoir interact.
As the industry advances on horizontal drilling and slim hole design, well completion and specifically hydraulic fracture stimulation remains the most expensive part of the well construction process in Unconventionals. Proppant and fluid make up a significant portion of the stimulation cost of a well, it is therefore a key lever in cost reduction. This submission will examine the transition from Conventional to Unconventional stimulation designs with respect to technical and economic factors that drive fluid and proppant optimization. The authors will then focus on the industry journey in multiple step change transitions from high viscosity fluid system with high strength premium proppants towards low viscosity fluid system and lower strength natural proppant. In each case, technical justifications based on theory, laboratory testing, or field trial data from Shell unconventional basins will be discussed.
Commercial-scale deployment of Carbon Capture and Storage (CCS) as a viable greenhouse gas emissions reduction technology requires that the CO2 be confidently contained in geological formations with no risk of groundwater contamination. To ensure containment is adequately monitored, an evaluation of what a potential leak could look like and how it can be detected is required. This paper is an example from the Quest CCS operation in Alberta, Canada.
Quest commenced operation in August of 2015 at a rate of 1 MT/year into two injection wells. After two years of operations, the project’s rigorous monitoring program has demonstrated that the reservoir is behaving as expected and no leaks have been detected. However, hypothetical leak paths have been investigated and modeled. Four scales of models have been used to evaluate the risks associated with the hypothetical leak paths and therefore on containment: (1) Geological structural models - Regional Static Model, Field Dynamic Model, (2) Legacy well - Well Brine Leak Path Model (3) CO2 Leakage - Injection Well CO2 Leak Path Model, and (4) Leak detection - Cooking Lake Model. The results of the modelling were used in the evaluation of the Quest project proposal, the current operating strategy, and the measurement, monitoring, and verification (MMV) plan.
The results of the leak path models demonstrate that the risk of a CO2 leakage from the Quest storage operation is very low. Regional modeling of the overburden confirmed that no leak pathways in the project area could be identified. Field level dynamic modelling demonstrated that injected CO2 is not expected to reach far field legacy wells, but the potential for elevated reservoir pressure displacing saline brine into usable ground water could be a risk if insufficient well count. The impact of a brine leak path was modeled and concluded to be negligible as the overlying under pressured cooking lake formation was concluded to be an effective pressure sink. As the injection wells have the highest pressures and concentrations of CO2 in the reservoir, despite excellent wellbore integrity, they are the most likely location for a theoretical CO2 leak path. It was both concluded that the buoyancy force was a very slow moving affect and that the cooking lake formation ultimately acts as a pressure sink. Therefore, the cooking lake was modeled to understand what pressure response could be expected and whether a leak into those formations could be detected. It was concluded that material leaks at the injection well would be differentiable from baseline pressure drift at the monitoring wells.
Our lives depend on reliable energy; if we are to prosper and tackle climate change, society must transition its economies and energy system to meet growing demand and emit less CO2.
Shell believes carbon capture and storage (CCS) is critical. CCS fitted to power plants could be a real game-changer, removing up to 90% of carbon dioxide emissions from power generation.
Engagement and cooperation with different stakeholder groups is key to maturing CCS projects. Shell has worked with stakeholders to help build a strong foundation for some of our CCS projects and this paper will share the approaches applied.
Collaboration is critical to achieving recognition of the scope and value of CCS and achieving acceptance for a specific project. It is important to create engaging outreach and educational initiatives that are targeted to the needs of the stakeholders, demonstrate commitment to local communities, address the points of challenge and clarification, make use of best practice and international project experiences and help bring CCS, energy and climate change to life.
Shell began its community consultation program for its Quest Carbon Capture and Storage (CCS) project in 2008 — three years ahead of filing a project application. A large part of our early consultation efforts were focused on explaining what CCS is, and why the technology is important. Consultation efforts focused on landowners and residents living along the proposed pipeline route and in close proximity to the proposed injection wells, along with the local municipal governments. A community advisory panel has been set up to review data from the Measurement, Monitoring and Verification (MMV) program. The program itself has been reviewed by an independent external expert.
The funding for the Peterhead CCS project has been withdrawn, but we are proud of the relationships established in the early phases of the project's development. The team carried out extensive consultations with the public to keep everybody up to date with plans as they progressed. We proactively sought and received feedback which we then endeavoured to build into our plans.
In addition, strong relationships were built with local, regional and international organisations to develop education-based initiatives around CCS and to build an effective approach to local content on the project, both with the aim of creating best practice learnings for the future.
At Shell, we believe the world will need to find ways to deploy CCS if it is to achieve its ambition to tackle climate change. In order to set CCS projects up for success, we must explore and develop a new model of cross-sector collaboration including: Building an understanding of the local context Engaging early - being present, responsive and inclusive Making communications engaging and relevant
Building an understanding of the local context
Engaging early - being present, responsive and inclusive
Making communications engaging and relevant
Successful engagement, collaboration and community presence can lead to strong, trusting relationships that can be built on over the life of the project.
Shell is progressing a portfolio of commercial-scale carbon capture and storage (CCS) demonstration projects covering an array of technologies that target applications of close relevance to the wider oil and gas industry. The portfolio includes projects such as Peterhead, Quest, Technology Centre Mongstad and Gorgon. A number of key learnings on both the technology deployment and critical project development aspects for the different project phases have been obtained. This paper provides an overview of these learnings with a specific focus on the issues faced by CCS project developers.
CCS is currently recognised as the only technology available for mitigation of carbon emissions from large-scale fossil fuel use. Before the process can be widely adopted it must be demonstrated at scale end-to-end. Learnings for all different project phases from early assess through to operations of these demonstrators need to be captured and communicated. As additional facilities to existing hydrocarbon operations, CCS projects require an approach similar to the development of other oil and gas projects.
To help enable and support other CCS projects, Shell is also committed to knowledge sharing from the projects, often agreed as part of the Knowledge Management provisions of the projects.
One of the key observations provided from the demonstration portfolio is the need for regular and informative engagement with both the public and regulators as the project progresses. Early and successful demonstrations can provide the evidence required for regulators, project developers and the public to have the confidence to proceed with future CCS projects.
It is also recognised that cost reduction will be key in driving commercial ‘deployability’ of CCS. The Quest and Peterhead projects are ideally placed to enable follow-on projects to learn and further reduce costs. The Shell portfolio of projects has also demonstrated that the drivers for technology optimisation can differ depending on the end user of the CCS technology. There is a need to demonstrate different technology aspects, for example flexibility or availability.
This talk will focus on how these issues are being addressed in two of the different projects within the Shell CCS portfolio, and highlight the key lessons learned. Furthermore, the cost-related issues of CCS will be addressed.
Verlaan, M. L. (Shell Canada Limited) | Hedden, R. (Shell Canada Limited) | Castellanos Díaz, O. (Shell Chemicals Americas Inc) | Lastovka, V. (Shell Chemicals Americas Inc) | Giraldo Sierra, C. A. (Shell Chemicals Americas Inc)
In recent years, the addition of a hydrocarbon condensate (C4 to C20) to steam operations (such as CSS and SAGD) in heavy oil and bitumen reservoirs has emerged as potential technology to improve not only oil recovery and but also energy efficiency. Shell has extended the idea of solvent addition to a steam drive process, applied it for the first time in the Peace River area in Canada, and obtained evidence of oil uplift in the patterns where solvent was injected. However, piloting this new technology in a brown field had many challenges, especially when evaluating its main economic factors: production increase and solvent recovery.
To overcome these challenges, emphasis was put on experimental design, data acquisition and quality, and production surveillance. The pilot conditions were designed to increase the probability of success on the two economic factors aforementioned within a short period of time. The assessment of the pilot required that all production streams (emulsion and casing vent gas) were metered and frequently sampled to measure their respective compositions. Cross calibration of metered and sampled water cuts was essential in obtaining conclusive production uplift data. Automatic proportional samplers were successfully deployed under these challenging conditions to obtain representative samples. Due to the overlap of solvent and bitumen components, special attention was taken to allocate hydrocarbon production into bitumen and solvent. New in-house developed algorithms were tested to accurately calculate this split.
The addition of a 4 month concentrated slug of solvent in two steam drive patterns resulted in a significant production uplift when compared to two adjacent patterns with steam-only injection. Solvent recovery is still ongoing and exceeds original expectations. Frequent sampling allowed the detection of several trends, including bitumen composition changes during solvent injection and solvent fractionation in the reservoir.
The steam-foam process is an Enhanced Oil Recovery (EOR) method which aims to improve the performance of a traditional steam drive by using a foaming surfactant. A Canadian thermal project under development in NW Alberta, which will use steam drive to recover extra heavy oil from the Bluesky Reservoir, is a good candidate for the application of steam-foam. A pilot test is planned to evaluate the benefits of the steam-foam process in this reservoir.
The steam-foam process is based on the use of a surfactant which, when co-injected with steam into the formation, generates foam. A candidate surfactant for steam-foam should be able to generate stable foam at high temperature, have a good thermal stability, a low rate of adsorption on the rock, and good solubility in brine. An experimental plan was designed to screen for appropriate surfactants to use in the field. Bulk foam height tests at high temperature, thermal degradation tests and static adsorption tests with disaggregated rock were carried out to screen the best surfactant. Two candidate surfactants were chosen based on the results. A pilot test plan was also developed for a proof-of-concept test of the candidate surfactant in the field. The primary success criterion for the test is an increase in the Bottom Hole Pressure (BHP) of the injector well after the start of surfactant injection.
Core-flooding tests are currently underway to confirm the performance of the candidate surfactant in the porous medium and determine the value of parameters required for the pilot design. The generation of strong foam in the formation should result in not only a BHP increase in the injector, but also improvement of the Steam to Oil Ratio (SOR) and ultimate recovery. The oil uplift response is dependent on the pattern geometry and geology of the reservoir and may not be observed immediately. However, the BHP increase will be immediately observed provided that strong foam has been generated near the wellbore, and this is the focus of the proof-of-concept test. A more extensive field test is planned for a later date to evaluate SOR improvement and recovery uplift.
Przybysz-Jarnut, J. K. (Shell Global Solutions International B.V) | Didraga, C. (Shell Global Solutions International B.V) | Potters, J. H. H. M. (Shell Global Solutions International B.V) | Lopez, J. L. (Shell International Exploration & Production Inc.) | La Follett, J. R. (Shell International Exploration & Production Inc.) | Wills, P. B. (Shell International Exploration & Production Inc.) | Bakku, S. K. (Shell International Exploration & Production Inc.) | Xue, Y. (Shell International Exploration & Production Inc.) | Barker, T. B. (Shell International Exploration & Production Inc.) | Brouwer, D. R. (Shell Canada Limited)
Time-lapse seismic surveillance is a proven technology for areal conformance monitoring offshore, but not onshore due to its high cost and typically poor data quality in that environment. Yet a number of examples in the industry show that nonuniform reservoir sweep is common in IOR and EOR projects and, if not addressed, it can significantly reduce ultimate recovery. In such projects the efficacy of injectants such as water, steam, gas, and solvents needs to be maximized to reduce cost and environmental footprint. This requires that we know what happens in-between wells, and for this purpose we conducted a pilot of high fidelity frequent seismic monitoring of thermal EOR redevelopment in one of the production pads in the bitumen deposits in Peace River, Canada. We detected patterns that can be directly linked to dynamic reservoir changes on a weekly or more frequent basis, such as pressure increase during injection, fluid phase changes, and connection to previously stimulated zones. The data also highlight the imprint of previous operations on the reservoir state prior to the current redevelopment, stressing the challenges faced when managing steam conformance. Our observations indicate that frequent time-lapse seismic images significantly contribute to determining injection/production strategy adjustments aimed at improved areal steam conformance.
To maximize the development value of the emerging Canadian Duvernay liquid rich shale (LRS) play quality risk-based decisions need to be made. These decisions must consider a number of complex variables that can all have a high impact on both short and long term economic viability. Credible ranges for variables such as well construction costs, production decline rates, infrastructure configurations, and commodity prices (e.g. oil price volatility witnessed in 2014) must be built. Quality decisions can then be made by leveraging a detailed understanding of the variables’ interdependencies and quantified economic impacts.
This paper describes the construction and analysis of a suite of Duvernay scenarios developed by Shell Canada using sophisticated hydrocarbon planning software. They were built using a strategy table approach and focused on options for gas processing facilities. The impacts of drilling ramp-up timing, shallow cut versus deep cut configurations, and operator versus midstream build-own-and-operate (BO&O) were examined. For example, several midstreamers exist in the Duvernay play area with significant, non-optimal (sour and shallow cut) processing capacity. These facilities can be used today to capture initial value but require expansion in the future; therefore, an evaluation of all credible new build options is required to understand how best to develop the play.
A suite of key comparative economic metrics, including net present value (NPV), profit to investment ratio (PIR), and payout period (POP), was generated. Expected monetary values (EMV) for each scenario were calculated and used to identify the optimal, risk-based approach. Additional insights were derived by comparing the scenarios, these insights included: the value of information associated with a longer appraisal period, the value of infrastructure flexibility, and the NGL recovery and product price thresholds required to justify deep cut construction.
Multi-scale simulation in coupled fluid flow- geomechanical systems is a computationally efficient method for numerically solving large poroelastic systems. When using multi-scale methods, care must be taken in ensuring consistency when information is exchanged between systems that have a different discretization. Here a method is presented which provides consistency between the pore pressure being calculated on a fine scale fluid flow domain and upscaled to the coarser scale geomechanical domain and the pore volume change being calculated on the coarse geomechanical domain and down-scaled to the fine fluid flow domain. Central to this process is the characterization of the mechanical properties of the poroelastic system at both scales.
Another advantage of the method presented here is that it is applicable to hydraulically disconnected but laterally drained (i.e. multi-porosity) layered systems as well as hydraulically connected, layered systems. Thus it can be used in geological situations where thin shale streaks or hardpans impede flow between laterally extensive, hydraulically conductive units. This is significant as the pressure evolution of such a hydraulically disconnected, laterally drained system can be very different than a hydraulically connected one as shown here.
A multi-scale treatment of fluid flow and deformation is a key enabler when simulation of poroelastic phenomena is limited by computational resources. As the spatial domain of the geomechanics model is usually larger than the fluid flow model, it is desireable to use a coarser discretization in the geomechanical model compared to the fluid-flow model. This type of multi-scale simulation requires a consistent up-scaling of pore pressure from the fine scale fluid flow model to the coarse scale geomechanical model and down-scaling of pore volume change from the geomechanical model to the fluid flow model (see Figure 1).