Martins, Ana (Nederlandse Aardolie Maatschappij) | Marino, Marco (Nederlandse Aardolie Maatschappij) | Kerem, Murat (Shell Global Solutions International) | Guzman, Manuel (Shell Global Solutions International)
This paper presents the first comparison between two different injection methods for foam assisted gas lift. Useful information for operators and technology developers are also provided concerning chemical selection, testing, and deployment of this hybrid artificial lift technology in the field.
The trials have been conducted in a gas lifted oil well with severe slugging and water cut above 50% (selection criteria as per SPE-184217-MS). The surfactant was delivered through a dedicated capillary injection string during the first trial, and the effects of surfactant concentration and depth of injection were evaluated. During the second trial, the surfactant was injected into the gas lift stream at the surface. Different surfactants were utilised for both trials based on stability concerns and method of injection.
Both trialled injection methods successfully stabilized the well flow, terminating severe slugging while increasing the drawdown and delivering an increase in gross production of circa 200%. These results, together with the downhole pressure data collected during the first trial, confirm that the surfactant starts foaming only at the depth where the lift gas enters the tubing. Injecting surfactant into the lift gas stream required higher concentrations than using a dedicated injection string, difference attributable to the slightly different chemistry, but even at those higher concentrations an anti-foamer injection was not required.
Concerning the response time, the well responded in 30 to 60 minutes with capillary string injection, while 6 to 12 hours were required for injection into the lift gas stream. This suggests that the surfactant probably moves slowly down on the annulus walls as a liquid film rather than travelling in droplets dispersed in the gas phase. Based on the outcome of the two trials, it is concluded that the injection via the lift gas stream is as effective as capillary string injection, at a fraction of the initial costs, with lower maintenance requirements, while still allowing access to the well.
This paper summarizes a technology using SMP to provide downhole sand control in openhole environments. With multistage operations becoming the industry norm, operators need easily deployable diversion technologies that will protect previously stimulated perforations and enable addition of new ones. This paper reviews several aspects of the use of in-stage diversion. Development of a new polymer composite that degrades via hydrolysis in hot water or brine holds potential for use in structural applications for intervention-less downhole tools. The polymer-injection project in the Dalia field, one of the main fields of Block 17 in deepwater Angola, represents a world first for both surface and subsurface aspects.
The contract is helping to solidify Europe’s offshore sector as the focal point for the rise of automated drilling technology. Drilling: What Can We Do To Thrive? Falling oil prices are the acid test of drilling efficiency. SPE Technical Director Jeff Moss of ExxonMobil talks about ways to build in lasting savings as part of this special report. The latest example of the offshore sector's march toward automated wellbore construction will take shape later this year in the North Sea.
The Society of Petroleum Engineers-Permian Basin Section (SPE) is collaborating with University of Texas Permian Basin's (UTPB) STEM Academy and Communities in Schools Permian Basin (CISPB) to kick-off the new school year with energy education! All oil and gas professionals and students are invited to participate in energy4me, SPE's initiative to educate K-12th graders about the importance of energy and practical STEM applications in the energy industry. Energy4me has lesson plans available for volunteers so they can immediately utilize and apply them for interactive activities and classroom discussions. The kickoff event is meant to benefit elementary to high school students of the UTPB STEM Academy and CISPB. Allowing the Permian Basin community to educate will foster the students' interest in STEM and inspire them to pursue STEM careers.
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Khare, Sameer (Cairn Oil & Gas vertical of Vedanta Limited) | Baid, Rahul (Cairn Oil & Gas vertical of Vedanta Limited) | Prusty, Jyotsna (Cairn Oil & Gas vertical of Vedanta Limited) | Agrawal, Nitesh (Cairn Oil & Gas vertical of Vedanta Limited) | Gupta, Abhishek Kumar (Cairn Oil & Gas vertical of Vedanta Limited)
The objective of the paper is to present the methodology adopted for dual artificial system modeling in Aishwariya field– an onshore oil field located in prolific Barmer Basin, India. This paper presents a conceptual and feasibility study of combination of Jet pump (JP) and Electrical Submersible Pump (ESP) together as means of artificial lift for production enhancement in a well. It discusses the workflow to model a well producing on dual artificial lift (ESP producing in combination with Jet-Pump) via industry standard software and demonstrates the same with a successful case study.
Requirement of ESP change outs to restore/enhance well production in cases such as undersized pumps, pump head degradation requires an expensive work-over. However, an option for secondary additional lift (JP) installation along with primary lift (ESP) in completion system can eliminate the costly wok-over requirement if both lifts can operate simultaneously.
The procedure to model the dual artificial lift (JP and ESP) has two major components: a) Psuedo IPR at ESP discharge node and b) Standard JP modeling using pseudo IPR. Pseudo IPR is generated by modifying well specific IPR using ESP pump curve for a specific frequency. The down-hole ESP pump intake & discharge pressure sensors help calibrate the model accurately for further prediction.
The existing completion in the Aishwariya field is ESP completion with the option of JP installation in cases of ESP failures as contingency. Moreover, jet pump can be installed using slick line with minimum well downtime (∼ 6 hrs). Therefore, installing and operating the Jet pump above a running ESP will not only increase the drawdown but will result in production enhancement with minimal cost.
The effectiveness of secondary and tertiary recovery projects depends heavily on the operator's understanding of the fluid flow characteristics within the reservoir. 3D geo-cellular models and finite element/difference-based simulators may be used to investigate reservoir dynamics, but the approach generally entails a computationally expensive and time-consuming workflow. This paper presents a workflow that integrates rapid analytical method and data-analytics technique to quickly analyze fluid flow and reservoir characteristics for producing near "real-time" results. This fast-track workflow guides reservoir operations including injection fluid allocation, well performance monitoring, surveillance, and optimization, and delivers solutions to the operator using a website application on a cloud-based environment. This web-based system employs a continuity governing equation (Capacitance Resistance Modelling, CRM) to analyze inter-well communication using only injection and production data. The analytic initially matches production history to determine a potential time response between injectors and producers, and simultaneously calculates the connectivity between each pair of wells. Based on the inter-well relationships described by the connectivity network, the workflow facilitates what-if scenarios. This workflow is suitable to study the impact of different injection plans, constraints, and events on production estimation, performance monitoring, anomaly alerts, flood breakthrough, injection fluid supply, and equipment constraints. The system also allows automatic injection re-design based on different number of injection wells to guide injection allocation and drainage volume management for flood optimization solutions. A field located in the Midland basin was analyzed to optimize flood recovery efficiency and apply surveillance assistance. The unit consists of 11 injectors and 22 producers. After optimization, a solution delivering a 30% incremental oil production over an 18-month period was derived. The analysis also predicted several instances of early water breakthrough and high water cut, and subsequent mitigation options. This system couples established waterflood analytics, CRM and modern data-analytics, with a web-based deliverable to provide operators with near "real-time" surveillance and operational optimizations.
The effects of horizontal well geometry remain debatable in most production modeling works. Most of recent reports fail to mention the effects of well geometries, especially in severe slugging cases. This study presents a qualitative comparison between different well geometries and their impacts in production performance of horizontal wells.
The study utilizes a transient multiphase simulator to mimic the production from a horizontal well over a 12-hour period. The well has a 2-7/8″ ID tubing with TVD of approximately 5000 ft and MD of 10000 ft and maximum inclination angle of 10º within the horizontal section. The trajectories of horizontal section in the well include 5 cases, 5 undulations, hump (one undulation upward), sump (one undulation downward), toe-up and toe-down. These configurations are the representative examples of horizontal wells. A reservoir with a given deliverability equation and several perforation stages is used to provide well inflow. The impacts of reservoir deliverability, GOR, pressure and temperature are studied for all well geometries.
The simulation results offer some valuable insights into the effects of well trajectory on production performance, including borehole pressure profile, liquid holdup, gas and liquid rate variations with time, and cumulative gas and liquid production. At high production rates, severe slugging is not observed, and thus, the well geometry effects are minimized with a consistent production at the surface. However, toe-up configuration exhibits a slightly better performance than the others.
As the productivity and pressure reduces throughout the life of a well, the impacts of well trajectories become clearer. The presence of severe slugs and blockage of perforations near the toes causes a noticeable drop in production. During severe slugging, the pressure profile reveals longer fluctuation cycles, resulting in extreme separator flooding issues. The slugging frequencies are compared among different well geometries. Toe-down case exhibits lower slugging severity. As a result, toe-down well produces the highest cumulative liquid and gas rates. The presence of liquid blockage is observed in lateral and curvature sections. The toe-up and hump configurations exhibit the most severe slugs with minimum cumulative gas and liquid productions. The differences in productions among well trajectories exceed 30% under different well configurations.
With the augmented growth of production from unconventional reservoirs, horizontal well technology has grown in oil and gas industry, yet study of well geometry in production system remains to be limited. This study is a unique effort to optimize well configuration and perforation placement in order to alleviate multiphase flow problems in the wellbore. Providing the practical potential on simulation works, this study provides a predictive guidline to connect well geometry selection and production optimization.
Gupta, Anish (PETRONAS) | Narayanan, Puveneshwari (PETRONAS) | Trjangganung, Kukuh (PETRONAS) | Mohd Jeffry, Suzanna Juyanty (PETRONAS) | Tan, Boon Choon (PETRONAS) | Awang, M Rais Saufuan (PETRONAS) | Badawy, Khaled (PETRONAS) | Yip, Pui Mun (PETRONAS)
A matrix stimulation candidate screening workflow was developed with the objective to reduce the time and effort in identifying under-performing wells. The workflow was initially tested manually for few fields followed by inclusion in Integrated Operation for an automated screening of wells with suspected formation damage. Analysis done in three fields for stimulation candidate selection will be displayed with actual statistics.
The main aim of the work was to digitalize the selection of non-performing candidates rather than manually looking into performance of each well. A concept of Formation Damage Indicator (FDI) was combined with Heterogeneity Index (HI) of the formations to screen out the candidates. Separate database sets of Reservoir engineering, Petrophysicist and Production was integrated with suitable programming algorithms to come up with first set of screened wells evaluating well production performances, FDI and HI trends up to over the last 30 years. The shortlisted candidates were further screened on the basis of practical approach such as gas lift optimization, production trending, OWC-GOC contacts, well integrity and well history to come up with second round of screened candidates. The final candidates were analyzed further using nodal analysis models for skin evaluation and expected gain to come up with type of formation damage and expected remedial solution.
For fields A and D with a total of 210 strings each, the initial FDI and HI screening resulted in 70 and 120 strings being shortlisted, respectively. This was followed by a second round of screening with 25 and 35 strings being further shortlisted as stimulation candidates, respectively. Nodal analysis models indicated presence of high skin in 90% of the selected wells indicating a very good efficiency and function-test of the workflow. In addition to selection of the candidates, the identification of formation damage type was compiled on an asset-wise basis rather than field basis which helped in more efficient planning of remedial treatments using a multiple well campaign approach to optimize huge amount of cost. The entire screening process was done in one month which was earlier a herculean task of almost one year and much more man-hours. With effective manual testing of the workflow in two major fields, workflow was included in Integrated Operations for future automation to conduct the same task in minutes rather than months.
With this digitalized unique workflow, the selection of under-performing wells due to formation damage is now a one click exercise and a dynamic data. This workflow can be easily operated by any engineer to increase their operational efficiency for flow assurance issues saving tons of cost and time.