Controlling steam conformance in the horizontal injectors of SAGD projects is widely accepted as being critical for commercial success. This work is focused on steam distribution in horizontal injectors in mobile, heavy oil (non-bitumen), thermal development projects. Steam Conformance can be achieved by tubing or liner deployed FCD's (flow control devices). Liner deployed FCD's have several advantages over tubing-deployed FCD's which includes: smaller tubulars, lower capital costs, reduced well interventions, and potentially reduced surveillance requirements.
This paper provides an overview of a collaborative development methodology for liner-deployed FCD's in horizontal steam service between a service company and operator. This methodology included: Establishing functional, operational and dimensional basis of design Computational fluid dynamics (CFD) analysis of the FCD design and phase-split testing in the Horizontal Steam Injection Test Facility (HSITF) Design revisions based on CFD, HSITF and shift testing results Field installations results based upon fiber optic, thermo-hydraulic, and mechanical analysis
Establishing functional, operational and dimensional basis of design
Computational fluid dynamics (CFD) analysis of the FCD design and phase-split testing in the Horizontal Steam Injection Test Facility (HSITF)
Design revisions based on CFD, HSITF and shift testing results
Field installations results based upon fiber optic, thermo-hydraulic, and mechanical analysis
These FCD's were designed with sliding-sleeve technology to enable opening or closing of each device. Different specifications of electroless nickel (EN) coatings were also tested to determine the performance for scaling and corrosion resistance. Within 6 months, three versions of the FCD's were tested in the HSITF with accompanying CFD. For each version the shifting forces before and after ~6 weeks of steam injection were measured. Each generation was improved based on the data from the prior version.
In December 2018, three FCD's were installed in a large bore horizontal steam injector in a tubing deployed completion for field qualification of the devices. This installation was the first step of a one-year field qualification test. The full test will involve multiple interventions to opening and closing the FCD's. A capillary tubing with fiber optic wrapped around the tubing and devices can confirm FCD openings or closings. The field qualification will also test the local operational capability to shift the FCD's. At the end of the field qualification, the flow devices will be retrieved for inspection and identification of further design improvements.
Yang, Xinxiang (University of Alberta) | Kuru, Ergun (University of Alberta) | Gingras, Murray (University of Alberta) | Iremonger, Simon (Sanjel Energy Services Inc) | Taylor, Jared (Sanjel Energy Services Inc) | Lin, Zichao (University of Alberta)
Stress-induced fractures in wellbore cement can form high-risk pathways for methane or carbon dioxide leakage yet little to no quantitative information on the impact of these fractures has been reported. To investigate this, scanning electron microscopy (SEM) and micro computed tomography (micro-CT) techniques were utilized to quantify the 2D and 3D geometrical parameters of cement fractures in mature thermal thixotropic cement samples that were subjected to pre-and post-peak compressive stress. A novel simulation method was also proposed to quantify the impact of the stress-induced realistic 3D fractures on the cement permeability. Results show that: i-) For pre-peak samples, 90% of the 2D fractures have length and width smaller than 100 μm and 5 μm, respectively. Although higher compressive stress reshaped the 3D fractures and increased the fracture length and width, no well-propagated fractures were observed; ii-) For post-peak samples, distinctly visible ( 0.1 mm) well-propagated fractures were generated but failed to penetrate the entire sample, therefore the effect of stress-induced fractures (up to 1.0% strain) on cement sample's permeability is limited; and iii-) CTbased 3D visualization and simulation both show that inclusion of a correctly engineered fiber additive is able to blunt the fracture propagation in cement samples. We conclude that up to the uniaxial compressive strength, the monotonic compressive stress is not likely to create leakage pathways in wellbore cement since the 2D fractures observed in SEM images are in limited dimensions and the large 3D fractures characterized in CT images have poor connectivity. Inclusion of a fiber additive is expected to enhance cement integrity by limiting the fracture propagation.
Rock deformation and fracturing is an important causal mechanism that can compromise well integrity. Geomechanical simulation is a valuable tool to investigate this mechanism and connect well tubular designs with reservoir development strategies. Utilizing relevant field examples, this paper describes a work flow in these regards.
Two example simulation approaches are described. One is to use a composite casing/cement/rock model in a reservoir of complex geology to compute maximum strain, dogleg severity, and ovality/restriction in the casing along the well trajectory. Different well design parameters, such as casing size, grade, and cement thickness, can be iterated against different reservoir production strategies. All these efforts are to arrive at an optimized design. The other approach is to calculate localized shear displacement along a weak plane that will be imposed on well tubulars during reservoir activities. The resulting design is optimized by altering well placement and stimulation/production schedules.
The above workflow has been proven in various field applications. Experience is shared in this paper. It is hoped this work can demonstrate that the optimal management of well integrity can be achieved by an integrated approach that designs appropriate tubulars and adjusts reservoir activities. Placing well tubulars in the context of rock deformation, geomechanical simulation is the best tool to connect the reservoir activities with the well tubular designs and therefore, can potentially offer a cost-effective well integrity management program.
The goal of this paper is to present the philosophies for the qualification and flow loop testing of FCD nozzles as well as the macroscopic implementation and operations of FCDs in SAGD producer wells. A quantitative methodology to evaluate FCD nozzles to choke back steam will be presented. Flow loop testing data will be shown to illustrate the qualification process. We will also discuss if sand control screens should be put on the tubing deployed inflow control devices. Some modeling and field examples will be shown. In the end, field data of the SAGD producer wells installed with the FCDs will be presented. Experience to manage and operate the wells will be shared.
Phi, Thai (University of Oklahoma) | Elgaddafi, Rida (University of Oklahoma) | Al Ramadan, Mustafa (University of Oklahoma) | Ahmed, Ramadan (King Fahd University of Petroleum & Minerals) | Teodoriu, Catalin (University of Oklahoma)
Most untapped promising energy resources in the world are associated with extreme downhole environment conditions. Applying the conventional method of well construction and operation for extreme downhole conditions poses severe challenges for the safety and longevity of the well. Governments and independent standardization organizations have developed several regulations regarding maintaining well integrity. Nevertheless, methods of completing and operating Extreme High-Pressure-High-Temperature (XHPHT) wells as well as geothermal wells have not yet been standardized. Preserving well integrity throughout the life cycle of a well is very crucial. Failure in well integrity can lead to huge operational and environmental risk and increase the energy cost.
This paper critically reviews the causes and solutions of well integrity issues in XHPHT and geothermal wells. After giving an overview of these wells, the paper discusses the well barriers at different ages. It also presents the conditions that lead to well integrity issues. Furthermore, the article discusses comprehensively the influence of acidic environment on cement and casing degradation at HPHT and summarizes the most recent research findings and development strategies in mitigating the integrity issues.
Previous studies revealed that the integrity of well barriers is highly affected by the degradation of drilling and completion fluids, cement, and tubular materials. The main causes of the well integrity loss are the lack of understanding of downhole conditions, inappropriate well construction practices, poor selection of the casing material and cementing type as well as inadequate design verification and validation on the downhole specimen. The well barriers are inter-related to each other as the destruction of one barrier may lead to the dismantling of the entire well barrier envelope. The XHPHT and geothermal wells share numerous similar barrier integrity issues, but they also have some unique problems due to the nature of their own operations. Although there is a significant advancement in solving the well integrity issues for the extreme downhole conditions, a sizable technology gap still exists in constructing and operating XHPHT and geothermal wells.
The current market conditions and the advancement in technologies are making the development of XHPHT wells more economically feasible. This paper serves as a review of the current research and development regarding well integrity issues for XHPHT and geothermal wells.
Soroush, Mohammad (RGL Reservoir Management, University of Alberta) | Roostaei, Morteza (RGL Reservoir Management) | Fattahpour, Vahidoddin (RGL Reservoir Management) | Mahmoudi, Mahdi (RGL Reservoir Management) | Keough, Daniel (Precise Downhole Services Ltd) | Cheng, Li (University of Alberta) | Moez, Kambiz (University of Alberta)
Accurate prediction of flow regime and flow profile in wellbore is among the main interests of production engineers in the quest of optimizing wellbore production and increasing reliability of downhole completion tools especially in SAGD projects. This study introduces a methodology for wellbore monitoring by detecting flow phase and flow regime. In order to develop this method, an advanced multi-phase flow injection experiment was designed and commissioned.
A flow injection setup was developed to test distributed fiber optic sensor installation under different operating conditions, including multi-phase flow (oil, brine and gas), and flow fraction scenarios. Different signal processing methods were applied to extract meaningful features and filter the noise from the raw signals. A statistical analysis was performed to assess the trend of the driven data. Then, typical SAGD models were simulated to assess the results of experimental setup for scale-up purpose and determination of local breakthrough of steam along the well.
Results showed that the Distributed Acoustic Sensing (DAS) data contains different levels of signals for each phase and flow regime. We also found that some level of uncertainties is involved in relating the flow regime and DAS information which could be resolved by improving the sensor installation procedure. In addition, the application of data-driven machine learning methods was found necessary to interpret the signal patterns. Initial results have shown that steam breakthrough along the well can be detected using real time DAS high energy/frequency signals. It can be concluded that including the DAS along with Distributed Temperature Sensing (DTS) is necessary to provide a better picture of steam conformance and SAGD wellbore monitoring. The limitations of the current experimental setup restricted further conclusions regarding the hybrid DAS and DTS application.
This paper is a part of an ongoing project to address the application of the combined DAS and DTS in SAGD projects. The ultimate goal is a downhole monitoring system to oversee the flow phase, flow regime and sand ingress in thermal application. The next phase will address the required improvements for developing a flow loop to handle high temperatures, include sand production and mimic thermal operation conditions.
During the lifetime of an oil/gas well, wellbore tubular structure might be subject to combined damage caused by both corrosion and mechanical wear. Therefore, it is necessary to conduct detailed stress analyses including these factors at the stage of tubular design.
An integrated well construction workflow was established for life-time well design. The temperatures and casing/tubing loads were obtained through numerical simulations of operations such drilling, stimulation, and production. All these simulations were accomplished using commercial software tools, including a thermal flow simulator and stress analyzer. On one hand, a commercial casing-wear simulator was used to predict the cumulative wear amount. On the other hand, a corrosion simulator was employed to predict pipe metal losses during each operation. The total amount of corrosion loss and mechanical loss were then compared against the maximum allowable wear for a safety check of the design.
The corrosion simulator was implemented in a computer program and integrated with the aforementioned commercial software of thermal flow and stress analysis. In a plot of maximum allowable wear versus depth, the curves of predicted wear, predicted corrosion, and predicted total metal loss are superimposed with the maximum allowable wear. This plot gives a straightforward and clear picture of the overall lifetime safety of the design.
A field case was studied with those integrated simulations. The production casing internal wear and internal/external corrosion were simulated. The predicted wear and corrosion data were in good agreement with the measured results. Further predictions provide rationales for future maintenance/workover operations.
Corrosion simulation and casing wear simulation were coupled with wellbore thermal flow analysis and stress analyses, helping proactively prevent tubular failure during the lifetime of the well. It is therefore valuable to include the integrated workflow during the wellbore tubular design where both corrosion and wear are involved.
Temperature fluctuations that occur during the service life of thermal enhanced oil recovery (EOR) wells are one of the primary design considerations for intermediate (production) casing systems from a long-term well integrity perspective. Restraint from the cement, formation, and surrounding well structure as the well is operated creates thermally-induced mechanical strain cycles that may impact various facets of casing integrity performance. A minor temperature reduction that occurs after the well reaches operating temperature will generally have less impact than a larger cycle that results in greater variations in mechanical strain and associated loading conditions. A more rigorous understanding of these effects will be beneficial, particularly as different sections of the well can be expected to go through different degrees of thermal cycling. Once the impact of these thermal cycles and their spatial variations on casing integrity performance is better understood, wells can be designed, constructed, operated and abandoned accordingly, reducing the associated integrity risks.
From a casing system design perspective, anticipating the impact of thermal cycles in light of expected operating conditions and associated service interruptions in applications such as steam-assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS) provides a means for enhanced confidence in design and well operation choices, and for reconciling long-term field performance with expectations. This paper describes an engineering framework for characterizing the impact of temperature excursions in thermal production casing given key structural integrity and connection sealability performance indicators, based on fundamentals of the mechanical behavior of this complex casing system and associated field practices.
The approach described herein is founded on the premise that thermal cycles of varying magnitudes in thermal EOR applications will affect key casing system performance indicators in different ways and to different degrees. For instance, the temperature reduction required to yield the casing body in tension during a shutdown will typically be much larger than the temperature reduction required to cause local yielding in the thread roots of the premium connections typically used for these wells. This methodology is intended to provide guidance for operators’ casing and connection evaluations considering anticipated well operating conditions and to support the development of integrity monitoring procedures that can target specific damage mechanisms arising from those conditions.
Novel elements introduced in this paper include the suggested systematic engineering approach to assessing the significance of thermal cycles on a variety of production casing system performance considerations, based on typical field and operational practices and available measurements. The authors also identify sample approaches that could be used to assess the impacts of thermal cycles on a variety of casing system performance criteria. The use of the framework should next be demonstrated using sample distributed temperature data; future developments could build on this approach and could be adapted to other applications.
Miller, Samantha M. (Noetic Engineering 2008 Inc.) | Smith, Kelcie T. (CNOOC Petroleum North America ULC) | Chartier, Mark A. (Noetic Engineering 2008 Inc.) | Meijer, Garret (Noetic Engineering 2008 Inc.)
Pipe installed in thermally stimulated wells is subject to high axial loads arising from the combination of axial constraint and temperature changes. These axial loads are manifested as applied strains, which are a function of the material thermal expansion behaviour, rather than applied loads. Variations in tubular strength and stiffness act to redistribute these strains and, in some cases, cause local strains to be significantly higher than the global average. This ‘strain localization’ can be particularly pronounced when the temperature change is sufficient to yield the pipe body and when the system is subject to variations in tubular constraint.
The energy industry has identified that a robust design must account for strain localization (
This paper provides an overview of strain localization in thermal well tubulars including discussion of the sources of constraint in both casing and liner, and discussion of the mechanisms that can trigger and exacerbate strain localization. The authors propose an analytical solution to calculate strain localization magnitude under basic conditions and demonstrate finite element methods for handling complex string designs and configurations. Finally, a case study provides an example of how the methods can be used to optimize string design to reduce the likelihood of problematic strain localization.
The discussion and finite element results provide an enhanced understanding of the mechanisms that will lead to strain localization and, in turn, provide guidance on what conditions to consider in the design of thermally stimulated wells. The analytical approach provides a practical approach to rapidly assess potential strain localization scenarios and ensure that those posing particular risk can be either characterized more rigorously or re-designed to minimize failure potential.
Nespor, Kristian (ConocoPhillips) | Chacin, Jesus (ConocoPhillips) | Ortiz, Julian (ConocoPhillips) | Morter, Julie (ConocoPhillips) | Romanova, Uliana (BHGE) | Bilic, Jeromin (BHGE) | Gohari, Kousha (BHGE) | Becerra, Oscar (BHGE)
Flow Control Devices (FCDs) are known to enhance efficiency of oil production, overall project economics and environmental performance that is currently of particular importance for Steam Assisted Gravity Drainage (SAGD) operators in Western Canada. FCDs have been utilized in SAGD wells over a decade, primarily, as liner deployed (LD) applications. Compared to LD FCDs, tubing deployed (TD) FCDs for SAGD producers are less common and require better understanding from the standpoint of completion design and operational strategy.
A study has been conducted on TD FCD installations in producer wells in the Surmont SAGD project. The study was aimed to understand failure modes and causes for several failed SAGD producers retrofitted with TD FCDs. Due considerations were given to key factors such as geology, runtime, operational practices and the possibility of failure of the slotted liner. Caliper log, fiber optics and downhole imaging data were used in the study. FCD strings pulled from the ground have been also analyzed.
All failures were found to be erosive wear with localized full wall loss of the TD FCD base pipe. No detectable erosion or other damage to FCDs are observed. As a general practice, a less aggressive operation strategy for wells with TD FCD compared to wells with LD FCDs was implemented after the study to avoid new failures. Proper screen sizing for TD FCD retrofits in slotted liner wells was identified as an important factor to provide effective sand control and may help reduce failures, but screen sizing was found not to have a direct effect on the failures investigated. The study shows that TD FCD retrofits have proven to be successful; however, special considerations are required when designing TD FCDs installations for SAGD producers, compared to LD FCDs, in order to reduce risk of erosive damage and failure.