Well Integrity engineers are commonly challenged with using limited resources, and even more limited data, when trying to identify which wells amongst their diverse well inventory may be prone to damage and failure, the mechanisms and influential factors responsible for the potential damage and failures, and the reason why certain wells may pose the greatest risk. Furthermore, these integrity engineers are often uncertain as to the parameters that should be tracked; what inspection methods should be conducted, in which wells and at what frequency measures should be taken; and how the asset risks can be adequately determined and relayed to management to prioritize near-term and future financial investments into well integrity and decommissioning cost centres. In this paper, an approach and workflow are described on how the application of a combination of reliability and risk methods, parameter-based damage models and available field data can be used to develop a tool used by asset integrity and operations personnel to risk-rank wells by the probability of failure and associated consequences. Additionally, this paper illustrates how the approach and models developed are adaptable to both the damage mechanisms specific to the application and to the data and parameters that are currently being measured or readily obtained, or other related variables that can used as suitable proxy parameters. As experience and history build (adding to the understanding and prioritization of damage mechanisms and key parameters), and to improve estimated values of the associated probability of failure due to these mechanisms, the knowledge is fed back into the model to improve its predictive capabilities. This paper also describes how the methodology was applied by a commercial SAGD operator to develop a subsurface isolation risk assessment tool that was tailored to their wells, their application conditions and the parameters that they measure. The types of static and dynamic parameters that this tool considers, including geologic, well design, construction and operational data, are also illustrated, as well as how the tool is being used to prioritize injection and production wells by relative risk. Illustrative examples of how well, pad and asset risks are being identified, rolled-up across the asset and summarized are presented, and how well integrity and risk metrics are being communicated within the company. Ongoing activities to continue to update and advance the risk-ranking model are also noted; in particular, potential opportunities to develop improved mechanistic and data-driven models and predictions of damage and failure likelihoods, based on pooled reliability data and information across the broader thermal recovery sector. 2 SPE-196081-MS
The majority of the models in the literature for the steam-assisted-gravity-drainage (SAGD) process solve the problem of conductive heat transfer ahead of a moving hot interface using a quasisteady-state assumption and extend the solution to the base of the steam chamber where the interface is not moving. This approach, as discussed by Butler (1985) and Reis (1992), results in inaccurate or sometimes infeasible estimations of the oil-production rate, steam/oil ratio (SOR), and steam-chamber shape. In this work, a new approach for the analytical treatment of SAGD is proposed in which the problem of heat transfer is directly solved for a stationary source of heat at the base of the steam chamber, where the oil production occurs. The distribution of heat along the interface is then estimated depending on the geometry of the steam chamber.
This methodology is more representative of the heat-transfer characteristics of SAGD and resolves the challenges of those earlier models. In addition, it allows for the extension of the formulations to the early stages of the process when the side interfaces of the chamber are almost stationary, without loss of the solution continuity. The model requires the overall shape of the steam chamber as an input. It then estimates the movement of chamber interfaces using the movement of the uppermost interface point and by satisfying the global material-balance requirements. Oil-production rate and steam demand are estimated by Darcy’s law and energy-balance calculations, respectively. The result is a model that is applicable to the entire lifetime of a typical SAGD project and provides more-representative estimations of in-situ heat distribution, bitumen-production rate, and SOR.
With the improved knowledge obtained on the fundamentals of heat transfer in SAGD, the reason for the discrepancies between the various earlier models will be clarified. Results of the analytical models developed in this work show reasonable agreement with fine-scale numerical simulation, which indicates that the primary physics are properly captured. In the final section of the paper, the application of the developed models to two field case studies will be demonstrated.
The Lower Cretaceous McMurray Formation in western Canada has over 1.8 trillion barrels of bitumen resource in place. Due to the bitumen in its natural state having a very low API (6-12°) and corresponding high viscosity, traditional primary (pump jacks) and secondary (water flood) recovery techniques cannot be used. Instead, economic extraction of the bitumen occurs via surface mining and subsurface steam-assisted gravity drainage (SAGD). Using the Pike and Jackfish oil sands project areas as a case study, it will be shown that successful SAGD operations requires a thorough understanding of the depositional fabric and stratigraphic architecture of the reservoir.
Within the study area, reservoir intervals in the form of cross-bedded sandstones and sandy inclined heterolithic strata (IHS) are present within both the middle and upper McMurray. Overlying the middle McMurray are upper McMurray parasequence cycles reflective of brackish bays and deltaic embayment deposits. In many areas, however, these parasequences are absent and instead substituted by fluvial channels with brackish water overprint. The facies within these fluvial channels are very similar in character to the those seen within the middle McMurray. To help progress our understanding of baffles and barriers to flow within these aforementioned reservoir facies, dip meter and seismic data are presented as data that can be used. From this, a better understanding of the complex interplay of facies and stratigraphic relationships can be made. More importantly, clearer insights into SAGD performance (pre- and post-steam) can also be achieved.
Using the McMurray Formation as an underpinning, the wider implications of understanding fluvial sedimentation will be addressed by using reservoirs from the Middle East as examples. For example, many siliciclastic reservoirs in locations such as Kuwait (Wara Formation) and Iraq (Zubair Formation) are also influenced to a large degree by fluvial sedimentation. Not unlike SAGD, any successful secondary recovery techniques applied within these reservoirs will also require a detailed characterization of the channel stacking patterns and channel orientations prior to implementation.
Steam Assisted Gravity Drainage (SAGD) producer wells in the McMurray formation require sand control technologies that will limit sand production while minimizing production constraints caused by high pressure drops and liner plugging. Previous publications around sand control selection and sizing for SAGD producers have provided varied and often conflicting design recommendations based on the expected formation sand particle size distribution. Small scale lab testing of sand control medium is often challenged with inconsistent results and uncertainty around the appropriate normalization for test comparison and scaling up to real-world applications. Devon Canada designed and constructed an in-house large scale liner testing apparatus to evaluate sand control technologies and determine the optimal aperture or filter size for sand types expected in the McMurray formation of the future Pike 1 SAGD project. The large scale liner testing results are presented in this paper along with the final recommendation for sand control on Pike SAGD producer wells. A brief review of the Pike McMurray sand typing and small scale liner testing is also presented.
Outflow Control Devices (OCDs) are commonly used in SAGD horizontal injection wells to enhance steam distribution in the well and facilitate uniform heating of the reservoir. Multiple devices are positioned in the tubing string across the horizontal portion of the well to create the desired steam distribution. Most OCD designs incorporate a sliding sleeve which is run in the closed position to allow steam to be circulated through the well. Circulation continues until sufficient injectivity can be achieved, allowing for bullhead steam injection. Post circulation, the sliding sleeves require coiled-tubing intervention to shift the sleeves open, activating the OCD. The subject method applies existing technology from horizontal multistage ball-activated completions to tubing deployed SAGD OCDs to eliminate the requirements for the initial coiled-tubing well intervention.
The ball-activated OCDs are activated by pumping degradable balls from surface to land in the OCD. Once landed, the tubing is pressured up to the predetermined shifting pressure, the sliding sleeve shifts open, and the ball disengages from the seat and continues to the end of the tubing string. This process is repeated with progressively larger balls for all the installed OCDs.
Product qualification has been completed to ensure SAGD service requirements are achieved. This includes ball degradation tests in boiler feed water, flow loop ball shift testing at ambient and elevated temperature, and mechanical tool shifting tests. The results of this testing are shared.
Through the elimination of the coiled-tubing intervention, significant operational efficiencies and cost savings are anticipated. In addition, the expected efficiency gain will minimize well down-time, resulting in less reservoir cooling and impact to production.
We present a case study of time-lapse joint PPPS inversion in an oil-sands reservoir and show the benefits of using this kind of inversion for the life of the oil-sands project. Inversion results were analysed and QC-ed against the temperature seismic volume (estimated from temperature logs and neural network analysis) and against new steam wells acquired shortly after the inversion was finished. Because of the reservoir heterogeneity, the steam chamber could have different shapes. High-quality multicomponent 3D seismic data for the baseline (2009) and the monitor (2015), along with core and well data have been used in imaging the steam effect in the reservoir. The results of our time-lapse joint PPPS prestack inversion add value to the life of the oil-sands project because: 1. Time-lapse P-impedance is a very good indicator for the steam chamber extension; 2. Time-lapse Vp/Vs is a good indicator of the zones where bitumen has become mobile and from where it will be produced; 3. Time-lapse density is good indicator of bitumen saturation.
High torque-and-drag (T&D) values can increase the difficulty of installing tubing in extended reach steam-assisted gravity drainage (SAGD) wells. Extra surface applied compressional force (tubing jacks) is often needed to land the tubing, leading to increased completion operation time and costs, and increased hazard potential. In many cases the likelihood of sinusoidal and helical buckling of the production tubing is also significant. A method of running tubing in extended-reach horizontal wells is presented which uses pipe floatation to reduce sliding friction in the lateral section. For SAGD wells in the subject area, the operator was able to eliminate the use of tubing jacks to run production tubing to the toe of the well. Data was acquired that allowed the comparison of tubing load conditions, both with and without the floatation method. This data was also compared with torque-and-drag (T&D) modeling results to illustrate the reduction in friction that was achieved and quantify the benefit of the method.
The method adapts principles used to float casing into wells to SAGD tubing installation, and moreover uses specifically designed floatation subs to increase the efficiency of the method. The floatation subs are used to trap air in sections of the tubing string in order to improve running forces. Once the tubing is landed, applied pressure is used to burst fragmentation domes within the floatation subs, leaving no obstructions in the tubing string.
In all trials of the float-in method, tubing was landed under its own weight, without using tubing jacks. In all of the conventional method wells, tubing jacks were needed to successfully land the tubing. Torque-and-drag models accurately predicted the point at which conventionally deployed tubing reached a neutral hookload.
Over the past several years, there has been a shift to drill longer wells with tighter inter-well spacing in projects using steam assisted gravity drainage (SAGD). An understanding of the impact on performance as a result of different well length and spacing can justify such a change for future well drilling. This paper examines the performance from various McMurray formation SAGD projects in the Athabasca region that have well pairs that are developed at different lengths and spacing. Changes in bitumen rate per well-pair, recovery factor and steam to oil ratio (SOR) were assessed at different well lengths and inter-well spacing. Certain performance characteristics from pads with tighter inter-well spacing were better than wider spaced pads. Furthermore, no significant changes in performance were noted in regards to changes in length.