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van Oort, Eric (The University of Texas) | Juenger, Maria (The University of Texas) | Liu, Xiangyu (The University of Texas, Currently with Nalco Champion) | McDonald, Michael (National Silicates, an affiliate of PQ Corporation)
Ordinary Portland cement (OPC) has been the material of choice for oil & gas well cementing and abandonment for many decades now. However, there are drawbacks to the use of OPC for cementing and abandonment purposes, particularly in wells with higher temperatures. OPC is brittle and does not re-heal when cracked. It is easily contaminated by mud and spacer fluids. Furthermore, it has relatively low tensile strength and low strength when bonding to rock formations and casing. Moreover, the production of OPC is the 2nd largest source of CO2 emissions in the world. At the CODA industry-affiliate consortium at the University of Texas at Austin dedicated to well construction, decommissioning and abandonment, work is ongoing to find technically superior alternatives to OPC. Particularly promising materials are so-called geopolymers, formed by activating an alumino-silicate material such as fly ash (a waste material that is often discarded) with an alkali. It was found that these geopolymer materials offer more ductile strength and failure behavior, considerable resistance to contamination, higher tensile strength and bond strength, and an ability to re-heal when damaged. The results obtained for geopolymers formed by activating flyash with potassium and sodium silicates indicate that these may be well-suited for achieving long-term thermal well integrity.
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.
In SAGD operations, the steam chamber temperature can be as high as 250 C. Foam formulations that can withstand such high temperature are required for field deployment of foam as conformance control technique. An evaluation of 12 surfactant formulations for their viability as steam foam candidate at chamber temperatures as high as 250 C is presented. Unlike other studies in the literature that used nitrogen for foam generation, methane was employed in this project. This project reveals that strong foam can be formed at 250 C. Also, foam is only generated within a specific range of methane mass quality. Stronger foam was formed when steam and methane were injected simultaneously into the core.
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.
Li, Jiankuan (University of Alberta) | Sun, Chong (University of Alberta) | Roostaei, Morteza (RGL Reservoir Management Inc.) | Mahmoudi, Mahdi (RGL Reservoir Management Inc.) | Fattahpour, Vahidoddin (RGL Reservoir Management Inc.) | Zeng, Hongbo (University of Alberta) | Luo, Jing-Li (University of Alberta)
This study presents an investigation of the on-site corrosion of carbon steel pipes with stainless steel mesh screens in a steam flood well in the Athabasca oil sand reservoirs to determine the failure patterns and mechanisms. To mitigate the corrosion of carbon steel, several candidate materials were selected, and their corrosion resistance was investigated.
In this work, the corrosion behavior and film characteristics of carbon steel pipes were studied by surface analysis techniques such as scanning electron microscopy, energy dispersive spetrocsopy and X-ray diffraction. Corrosion resistant alloys (proRSf and proRSc), anti-corrosion coating (proRA05a) and pre-treated steel (proRAQa) were considered as alternative materials to carbon steel (proRAa and proRAb) and their corrosion protection performance in brine solution was evaluated by electrochemical methods such as potentiodynamic sweep and electrochemical impedance spectroscopy.
Results show that severe erosion-corrosion occurred on inner wall of the pipes and caused significant wall-thinning of pipes along with localized corrosion damages, which is the dominant reason for base pipe failure. In spite of the slight corrosion on outer wall of the base pipe, severe localized corrosion appeared at the interface between the carbon steel pipe and stainless steel mesh screens due to the galvanic corrosion effect of dissimilar metals. The corrosion rates of the corrosion-resistant materials were two or three orders of magnitude lower than that of carbon steel. The corrosion resistance ranking order is proRSc > proRSf > proRA05a > proRAQa > proRAa > proRAb.
This study improves the material selection procedure in thermal operations by investigating several alternatives to carbon steel. It also provides a testing procedure to assess the corrosion resistance of the material in thermal applications.
For high pressure/high temperature (HPHT) and thermal wells, it is important to verify that the selected tubular connection product possesses adequate structural integrity and sealing capacity under the demanding load conditions typically experienced by these wells throughout their life cycle. Individual premium connection designs are typically evaluated and qualified to broadly adopted industry standards, such as ISO 13679 (2019) and API RP 5C5 (2017) for HPHT wells up to temperatures of 180 C, and ISO 12835 (2013) for thermal wells that experience temperatures from 180 C to 350 C. Proprietary operator-defined protocols are also used by some operators for connection qualification. While the current standards recognize that it is neither necessary nor practical for manufacturers to complete full-scale physical testing of the connection design for every different tubular diameter, weight and grade as a means to achieve full product line validation, the development of a practical framework and effective guidelines to achieve this outcome continues to be a work in progress. The basic approach allows interpolation and extrapolation of the results established through combined testing and analysis programs completed on a selected subset of sizes and weights of the full product line of the connection design. This paper starts with a review of current standards for qualifying tubular connections for HPHT and thermal wells. It presents guidelines and an approach to facilitate the performance evaluation and product line validation of connection designs based on the use of Finite Element Analysis (FEA) methods and the recently established sealability criterion. To illustrate the approach, parametric FEA case studies were completed to determine the impact of different tubular sizes and weights on the sealability performance of gas-tight tubing and casing connections under HPHT and thermal well loading conditions. Based on the analysis results, recommendations and considerations for ongoing research are made to improve the confidence in the use of interpolation and extrapolation methods presented in the current standards when conducting tubular connection product line validation exercises.
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.
Temperature and pressure changes are drastic during the warm-up phase (steam circulation) of SAGD wells as a result of introducing heat to cold tubulars. These drastic changes will impact casings as well as cement. Impacts of circulation strategy (fast vs. slow warm-up) for 11 ¾ in. intermediate casing with dual parallel completion design, on cement and casing were investigated previously. Current work focused on analyzing the impact of slow warm-up on smaller intermediate casing size (9 5/8 in.) for dual parallel and single string completion designs, the second one with vacuum insulation tubing (VIT).
The purpose of this paper is to complement the results of previous work in terms of using transient analysis to assess the impact of warm-up rates. The results of transient flow simulator data together with field data enable determining the effect of the warm-up period on different components of wellbore for different types of completions (small versus large wellbore, single versus dual string, uninsulated versus insulated tubing) from integrity perspective.
In this study, the dynamic flow simulations indicated that time for steam to reach the toe was almost the same for the dual string and the single string with VIT. In addition, the single string with VIT design eliminated instabilities in operational parameters (e.g. pressure) observed in the case of dual string. However, the single string with VIT case indicated that the heating rate of cement between the intermediate and surface casing string is the highest.
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.
Inflow Control Devices (ICDs) have been adopted for commercial steam-assisted gravity drainage (SAGD) production for nearly ten years and yet the function they serve is not well understood, and field data evaluating their performance remains scant. Thus, the purpose of the current study is twofold: Firstly, the study derives a simplified analytical model demonstrating how increasing the dP across ICDs acts to improve conformance along a producing lateral. The resulting equation of the analysis acts as a simple rule of thumb for determining an appropriate pressure drop across ICDs to achieve conformance. Secondly, the study evaluates the performance of ICDs that had been installed in four wells, two of which had ICDs installed prior to circulation and two that adopted ICDs later in their lifecycle. The field data shows that ICDs increase production rates and improve conformance along the lateral. These improvements are achieved by an increased drawdown facilitated by the ICDs. This part of the study highlights how early-life results may differ between ICD bearing wells compared to their conventionally completed (slotted liner) offsets, with the improved conformance and ability to develop more challenging reservoir resulting in different oil production profiles and composite SORs.