Saeedi, Majid (Pengrowth Energy Corporation) | Cowle, Jason (Pengrowth Energy Corporation) | Cross, Ryan (West Rock Energy Consultants Ltd.) | Stevenson, Jesse (Variperm Limited, Canada) | Tuttle, Aubrey (Variperm Limited, Canada)
Liner failure is one of the key risks in operation of SAGD producers and is often associated with erosion as a result of steam production (
Liner failures were diagnosed by analyzing the temperature data from fibre optics along with the performance indicators of the ESP pumps. Various remediation plans such as patching the failed intervals, using tubing ICDs or drilling a parallel lateral were considered. Using tubing deployed ICD systems along with blanked intervals was selected as the most practical solution to recover productivity from these wells. To size the ICDs and length of segments, a range of emulsion production volumes as well as estimated corresponding vapor and gas volumes were assumed. Furthermore, the risk of creating new hot points near the existing failed points or vapor producing intervals was considered.
The well workovers involved detailed planning of operations and services to effectively achieve cleanouts, maintain adequate inner wellbore diameter to run the swell packers and correlate DTS data with workover findings. The workover involved gauge runs, a jet-vac clean-out, a multi-finger caliper log and mud circulation of the wellbore for final solid removal to ensure successful installation of the new ICD systems.
The wells were put on production initially with low drawdown and slowly ramped up to let the packers set and sand to form bridges. After a few months of production, the wells were fully ramped up with production rate increasing 2 to 5 times the pre-workover rates. ESP pump performances is stable in both wells and the fibre optic temperature data show that failed liner intervals and hot points are well managed.
The intent of this paper is to share the processes and factors considered in using remedial ICDs and the learnings from the workover operations and startup of the wells.
Khunmek, Thanudcha (Mubadala Petroleum) | Abu-Jafar, Feras (Mubadala Petroleum) | Chigbo, Ikenna (Mubadala Petroleum) | Laoroongroj, Ajana (Mubadala Petroleum) | Mohd Ismail, Ismarullizam (Tendeka) | Parrott, Keith (Tendeka)
This paper describes a pilot program for the application of an Autonomous Inflow Control Device (AICD) by retrofitting an existing ICD completion for reservoir optimization. New drill horizontal wells were required to be completed with AICD's to enhance recovery with existing ICD completion materials in inventory desired to be used. The workflow for establishing the decision change from ICD to AICD completion and the completion design process change is discussed.
The well program was selected to demonstrate the effectiveness of AICDs in the Jasmine asset, a current field development in Thailand. ICD screens had previously been purchased for a different application but were unused. To reduce overall project cost and asset inventory, a method of utilization the existing ICD screens was strongly desired. An evaluation was done, followed by design and development of a manufacturing process to retrofit the ICD screens with larger sized AICD housing. Furthermore, overall completion design was implemented to ensure a smooth deployment and optimized production benefit.
Multiple joints of existing ICD screens were successfully retrofitted with AICD technology locally within the region. The operator was able to reduce current inventory book levels by 20% that resulted in a direct cost saving of 40% comparing to new AICD screen cost. The field deployment of the retrofit completion was a success without any operational issues.
Despite the improved productivity and uplift in reserve recovery associated with horizontal wells, reservoir heterogeneity can cause uneven production and early water and gas breakthrough from portions of the wellbore. The AICD delivers a variable flow restriction in response to the properties (viscosity) of the fluid with water or gas flow restricted. With multiple segmentation along the horizontal section in this application, excessive production of unwanted gas and water have been limited. Installed in late 2017 and another application in 2018, production from the wells have exceeded expectation, with an uplift in recovery.
The most common practice to deploy a lower completion with inflow control devices (ICDs) requires a washpipe assembly to facilitate deployment. Due to the nature of traditional ICDs, with open flow ports, the washpipe assembly provides a conduit to circulate fluids during the installation. However, makeup and break out of washpipe takes time, carries risk, and provides no long-term benefit to the completion or long term value to the operator. The industry has used temporary mechanical isolation in more recent years, but these devices lack redundancy in the event of malfunction. The objective of the hydro-mechanical ICD is to remove the requirement for washpipe, thereby reducing operational risk and rig time while eliminating HSE concerns related to drill pipe handling when deploying the lower completion. The key differentiator being additional redundancy, should manipulation be required. An additional feature of the tool is position verification, the ICDs benefit from a passive attenae. The attenae reader can be deployed in the future to independently verify sleeve position should well optimization be required over the well lifecycle as water cut increases. The paper reviews various techniques that have been adopted to date and concludes with presenting a hydro-mechanical solution that was successfully installed and the value derived.
To prevent or minimize problems associated with water coning in horizontal oil producers, inflow control devices (ICDs) are installed along the wellbore to better equalize the toe-to-heel flux. Nozzle-based ICDs are popular because they are: 1) easy to model accurately, 2) virtually viscosity independent, and 3) easy to install at the wellsite with many unique settings. Nozzles can be installed either in the wall of the base pipe (radial orientation) or in the annulus between the base pipe and housing (axial orientation). The advantages of the former are: 1) smaller max running OD, and 2) no need for a leak-tight, pressure-rated housing. One disadvantage is the high exit velocity that raises concern of erosion or erosion-corrosion of the basepipe.
To overcome this disadvantage, a new nozzle had been developed with a novel geometry that reduces the exit velocity about ten-fold compared to a conventional nozzle for the same pressure drop and flow rate. Computational fluid dynamics (CFD) was used to first fine tune the design to meet strict erosion-corrosion prevention requirements on the wall shear stress downstream of the nozzle for both production and (acid) injection directions, and then to develop flow performance curves for four different nozzles "sizes" that vary in their choking ability, thereby allowing many unique settings per joint at the wellsite.
Full scale prototype manufacturing and flow loop testing were then performed to validate the CFD flow performance predictions and to demonstrate mechanical integrity and erosion resistance for high rate production and injection. The results, as presented herein, demonstrate a robust and commercially viable ICD design that: 1) has predictable flow performance using CFD, 2) minimizes erosion and erosion-corrosion in either direction, 3) minimizes running OD, 4) simplifies the housing design, and 5) allows easy installation at the wellsite with 34 unique settings per joint. Also discussed are two new advantages over other ICDs that were not anticipated in the original development.
While it is understood that Inflow Control Devices (ICDs) can be an extremely valuable tool for reservoir management in certain applications, an engineering analysis is used to determine viability of ICDs for future developments. Typically, reservoir and production engineers use numerical reservoir simulation and/or steady state simulation to determine their applicability, evaluate various devices and configure their completions. Hence it is critical that the methods used to characterize the performance of the ICDs in these simulators are accurate.
For passive ICDs, the characterization is fit for purpose; however for Autonomous Inflow Control Devices (AICDs), despite their recent rise in popularity, the performance characterization has been limited to mathematically derived correlations that are adjusted to initial data. By using these mathematically derived correlations rather than physics-based modeling, the characterization is unable to predict critical flow for compressible fluids and critical flow caused by cavitation in the case of pure substance flow, such as water. By neglecting the effects of the physical phenomenas such as compressibility and cavitation, the simulation will result in higher gas production than reality for gas coning control applications and higher water production in thermal applications where the operational condition is close to water saturation.
Furthermore, fitting the correlations parameters for a wide range of fluid viscosities is complicated. This has led to several variants of correlation parameters that are dependent on specific ranges of viscosity. Hence, dynamic simulations can be complicated by the fact that the performance correlation factor has to be changed according to the fluid that is produced.
In an attempt to remedy these limitations, a typical AICD, considered an industry standard, was modeled using a mechanistic approach to capture the physics of the process as closely as possible. Existing sets of test data, some of which were publically available, for fluids ranging from 0.011 to 500 cP, were used to tune the mechanistic model and test the ability of reproducing the data.
The results have shown that the model has the ability to reproduce the flow loop test, effectively being able to predict compressible critical flow and performance of the device for a wide range of fluid viscosities. Furthermore, new experimental data was generated to test cavitation conditions that were included in a unified model. The unified model consolidates the expected operational window of the device, allowing accurate interpolation of non-tested conditions.
A new electronic sliding sleeve has been developed for hydraulic fracturing that combines the best features of traditional sliding sleeves and plug and perf techniques. This battery-powered electronic sliding sleeve provides the operational efficiency of sliding sleeves in an unlimited number of zones. The firmware, electrohydraulic lock, and electronics package in this new sliding sleeve help enable a range of operational functions for use in hydraulic fracturing.
Traditional sliding sleeves use a series of progressively sized balls that shift sleeves by landing on progressively sized baffles. An electronic sliding sleeve creates a monobore construction with the same inside diameter bore in each sleeve and helps enable treating of an unlimited number of zones. The electronics in the sliding sleeve helps eliminate the mechanical complexity of other monobore fracturing tools. The firmware and electronic package enable a modular approach to electronic sleeve design. Therefore, one frac sleeve chassis design can be used for many of the different types of sleeve tools in the well completion, and the firmware that drives the electronics is modified for each respective type of tool.
Using combinations of the electrohydraulic lock, electronics package, and firmware can enable the design of all the tools necessary to complete a wellbore. The standard firmware, used for a single point entry sleeve, operates by counting the correct number of frac balls. When the correct count is reached, the electrohydraulic lock is released, enabling sleeve movement or zonal isolation deployment. A modification can be made to the firmware to have the tool actuate on the next count, rather than the initial count, and delay the time at which the electrohydraulic lock is released. This type of architecture lends itself to the design of multi-entry sleeves. The sensor can also be eliminated by using the delay feature in the firmware of the electrohydraulic lock, programmed in weeks. This type of architecture also helps enable the design of a toe sleeve.
Having the ability to implement slight modifications to the components that make up the sliding sleeve enables design flexibility and modularity for all sleeve type tools necessary to complete a wellbore. This type of system architecture helps decrease operator risk and ease design constraints while performing multiple functions downhole.
Downhole control devices are being widely implemented in fields globally; and, because of the costs involved in their implementation, a robust reservoir performance forecast is necessary. A prerequisite to a sound reservoir development plan is to have a robust history-matched reservoir simulation model. This study involves use of a downhole inflow control device (ICD) well configuration in the reservoir simulation model to perform history matching of a green-field offshore Abu Dhabi. The results of this approach are compared to the results from traditional approaches. The scope of this study is to examine the differences in both history match approaches.
Reservoir A is one of the major reservoirs of a green-field located offshore Abu Dhabi, and is being developed with a five-spot water injection pattern. The producers and water injectors are horizontal wells, which are drilled across different flow units within the reservoir. Because the reservoir is heterogeneous across all the flow units, the injection pattern results in a non-uniform water front. The conventional approach to history matching the well performance is to implement a positive skin factor across the well completions to mimic the effect of the inflow control devices (ICDs) installed in the well: increasing the pressure drop (ΔP) between the formation and the well tubing. In this study, the actual downhole configuration was prepared using well-completion analysis software, followed by use of a next-generation reservoir simulator to run the full field reservoir model for the history matching period.
As the field is being developed on the principles of digital concept, continuous high-frequency downhole pressure data is available in flowing as well as shut-in conditions. The use of this data, coupled with direct modeling of the ICDs in the simulation model, resulted in a significant improvement in the reliability of the history match, as compared to traditional approaches.
This study compares two history matching approaches for fields with wells completed with downhole control devices. The core purpose of this study is to integrate the principles of the digital oil field with conventional history matching techniques, with the ultimate goal of improving the history match.
It is often stated that necessity is the mother of invention. Never is this proverb more relevant than in the offshore oil and gas environment we currently operate in where real step changes leading to reduced capital and operational expenditure opportunities are sought and embraced by field operators. This paper discusses the pre-job planning, field execution and lessons learned from one such technology that challenged conventional thinking of sand faced completion, casedhole completion and well integrity to successfully deliver a single-trip, interventionless, sand control completion in deepwater Bonga Field, located on the continental slope of the Niger Delta.
Convention dictates that the vast majority of offshore completions be run in two and sometimes three trips which routinely takes in excess of eight to ten days to deploy. Given the day rate of high specification rigs capable of drilling in deep water environments, the ability to reduce this time was deemed paramount to the economics of the project. Utilizing a collaborative approach to initial concept design, risk assessment, extensive testing and contingency planning at component and system level, a single-trip, interventionless, sand control completion system was designed and successfully installed. This paper describes the completion architecture, operational sequence and challenges leading to the installation of an interventionless completion.
A clearly defined set of deliverables and design principles were drawn up to guide the direction of the project including: successfully deploying the upper and lower completion in one trip, and testing all barriers. Adopting a simple, low risk and high reward design, meeting clients well barrier requirements and utilizing proven cost-effective technology are examples of design principles used. The system was tested and evolved through a number of iterations in an onshore trial well environment on a number of occasions leading to the first successful deployment completed in the second half of 2018, resulting in an average completion installation time of 5 days, versus the average 10 days for deploying multi-trip completions. Details of the successful installations, lessons learned, along with planned future activity are outlined within the body of this paper. While several of the components incorporated in the single-trip system had been run previously in isolation, this paper also discusses the steps taken to facilitate the first full-system approach to the application of radio frequency identification (RFID) enabled tools in the first single-trip, interventionless sand control completion system. Several components within the completion have been equipped with this technology including a multi-cycle ball valve, wire wrapped screens fitted with inflow control device (ICD), remote operated sliding sleeve for annular fluid displacement.
Autonomous Robotics’ first offering is built around a rounded yellow device that looks like a little flying saucer. Several designs for autonomous inflow-control devices (AICDs) are available. The comparative properties and abilities of these designs are the focus of this paper. Work conducted in the Surmont field of Alberta, Canada, provided an excellent starting point to optimize flow-control improvements to the SAGD process.
This paper discusses the first multilateral well with a Level-4 junction combined with an inflow-control device (ICD) planned, designed, and drilled in the Upper Burgan reservoir of Raudhatain field, north Kuwait. Several designs for autonomous inflow-control devices (AICDs) are available. The comparative properties and abilities of these designs are the focus of this paper. As part of a project that involves the use of four artificial islands to drill and complete more than 300 extended-reach-drilling (ERD) wells in a giant offshore oil field, several completion designs have been piloted for brownfield development.