Comparing Effectiveness Between Cemented Plug and Perf and Open Hole Ball Drop Completion Assemblies to Ensure Optimal Multistage Fracturing Treatment and Well Performance — Field Examples

Optimization of the Turnaround Time and Quality of Production-Screening Tests in Offshore Fields – Some Case Studies

10.2118/207105-ms ◽

2021 ◽

Author(s):

Stella I. Eyitayo ◽

Kazeem A. Lawal ◽

Ibrahim Abdullahi ◽

Saka Matemilola ◽

John Akadang ◽

...

Keyword(s):

Cost Saving ◽

Empirical Data ◽

Turnaround Time ◽

Screening Tests ◽

Well Performance ◽

Subsequent Test ◽

Expert Opinions ◽

Simple Strategy ◽

Open Hole ◽

Job Assessment

Abstract Production-screening test (PST) is performed on a reservoir drill-in fluid (RDIF) prior to running any component of the lower completion assembly that is vulnerable to plugging. This is applicable in open-hole completions in which wire-wrapped production screens are deployed. The key objective of a PST is to reduce the risk of plugging key completion components, such as production screens, during subsequent flow back. Hence, a PST increases the chance of preserving well productivity (or injectivity), ultimate recovery and project economics. However, conducting and achieving PST-quality RDIF in offshore fields can be cumbersome, time-consuming, and expensive, yet the quality is not guaranteed. This paper presents the formulation, implementation, and results of a simple strategy to reduce the turnaround time and costs of achieving PST-quality RDIF for applications in offshore fields. Employing a combination of on-the-job assessment, empirical data and expert opinions, the strengths and weaknesses of onsite versus offsite (onshore) options of preparing PST-quality RDIF for offshore operations are evaluated. As a case-study, empirical data from the execution of both onsite and offsite options for an example field are employed for the evaluation. Results of simple cost-time-benefit analysis underscore the robustness and competitiveness of preparing the PST-quality RDIF offsite and transporting same for subsequent test validation and application on the rig. The results of these empirical examples show that the offsite option yields about 75% cost-saving relative to its onsite counterpart. In addition to cost saving, other incremental benefits of the former include (i) significant reduction in rig time and personnel; (ii) improved RDIF quality; and (iii) higher chances of preserving well performance and economics. To increase the success rate, residual risks of the preferred offsite option are outlined, and relevant mitigations provided.

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Gamification in Training of Holistic Multidisciplinary Petroleum Asset Management

10.2118/208001-ms ◽

2021 ◽

Author(s):

Arthur Aslanyan ◽

Arkady Popov ◽

Rustem Asmandiyarov ◽

Andrey Margarit

Keyword(s):

Asset Management ◽

Real Life ◽

Development Planning ◽

Well Test ◽

Well Performance ◽

Learning Program ◽

Remote Communication ◽

Well Drilling ◽

Warm Up ◽

Open Hole

Abstract The paper shares a 4-years’ experience of "Gazprom Neft" PJSC on Digital Twin Learning Program in training of holistic multidisciplinary petroleum asset management and engineering based on the on-line cloud PetroCup software facility. The objective of the program was to train and test large amounts of managers and engineers with minimum off-work time and motivate self-improvement among the employee. The program includes warm-up videos, immersive master-classes, training courses, discussion clubs and Annual Corporate Championship, with a strong focus on home learning, remote communication, simulation-based exercises and automated testing/certification. The program is divided into Master Development Planning (MDP) and Well & Reservoir Management (WRM) domains which are related to different stages of the petroleum asset lifecycle. The interaction with simulator takes 2-3 days for WRM and 5 days for MDP and engages a multidisciplinary team: asset manager, economist, contract engineer, surface facility engineer, reservoir engineer, geologist, petrophysicist, simulation engineer, well test engineer, well and log analyst and production technologist. The session starts by reading the existing field data and its history and then perform well drilling, completions, workovers, well tests, open-hole and cased-hole logging, manage production and injection targets, build/modify the surface production/injection facilities and receive the fully automated asset response in the form of the field reports, very much in the same way as in real life. Once session is over the simulator generates a detailed debriefing report on team performance in numerous areas: economical, production, injection, reservoir and well performance so that team can understand where it did a good job and where it was not efficient. The current paper shows how this facility has been integrated into the corporate staff capability program, expanded to anchor universities and shed the light to the future perspectives.

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Evaluation of Horizontal Well Performance After Drilling-Induced Formation Damage

Journal of Energy Resources Technology ◽

10.1115/1.1924463 ◽

2005 ◽

Vol 127 (3) ◽

pp. 257-263 ◽

Cited By ~ 12

Author(s):

Y. Ding ◽

G. Renard

Keyword(s):

Horizontal Well ◽

Oil And Gas ◽

Horizontal Wells ◽

Integrated Approach ◽

Formation Damage ◽

Well Performance ◽

Wellbore Modeling ◽

Open Hole ◽

Testing Techniques ◽

Study Laboratory

It is well recognized that near-wellbore formation damage can dramatically reduce well productivities, especially for open hole completed horizontal wells. The economic impact of poor productivity of these wells has pushed toward significant efforts in recent years to study laboratory testing techniques and numerical modeling methods for predicting and controlling drilling-induced formation damage. This paper presents an integrated approach, combining a near-wellbore modeling with laboratory experiments for data acquisition as input for the model, to evaluate the performance of oil and gas wells after drilling-induced formation damage.

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Development and Trial of Technology for Open Hole Wells Performance Enhancement in GoM

10.4043/31190-ms ◽

2021 ◽

Author(s):

Luis Peixoto ◽

Wilfred Nathaniel Provost ◽

Jesse Thomas Gerber

Keyword(s):

Filter Cake ◽

Performance Enhancement ◽

New Technology ◽

Injection Rate ◽

Differential Pressure ◽

Successful Implementation ◽

Well Performance ◽

Noticeable Effect ◽

Open Hole ◽

Well Injectivity

Abstract Open hole (OH) completions are not very common in the GoM, but the area has seen an uptick in OH wells in recent years, and a few big projects have elected to use the same completion archetype. There are several different ways to complete an OH well, and one of these completion techniques involves running screens across the OH in Drill-In fluid (DIF), displacing the DIF out of the OH with brine, and then setting the packer, before pumping a filter cake breaker, designed to remove the filter cake and restore the reservoir permeability to near pre-drilling levels. A review of past open hole (OH) well completions in GoM revealed that there was an inconsistent action of the breaker on the filter-cake: sometimes the breaker would react quickly, and sometimes there was no noticeable effect. This study led to the development of a new technology to allow better displacements of the OH, with the ultimate objective of reducing initial well skin induced by the drill-in fluid (DIF) and filter cake. It was theorized that the low displacement rates would lead to poor removal of the mud from the OH, in turn leading to a poor breaker action on the DIF filter cake and a long-term impact on well injectivity and increased OPEX, as these wells tend to need an initial stimulation within a short timeframe after initial completion. The approach used was to develop a new tool to allow faster displacement rates, and test it on a trial well, to verify the results and validate this theory. To solve this problem, a new tool was proposed, developed and fully tested in a tight deadline of 6 months. The new module allows up to 9 bpm rates and up to 3,500 psi differential pressure before setting the packer, versus the previous ∼800 psi differential pressure limit, present in all tools in the market, for that casing size (7 5/8"). During the first well trial, the tool allowed a displacement of the OH at double the pump rates obtained in previous wells in the same basin, with similar OH lengths, leading to the smallest volume of contaminated fluid interface seen to date, indicating a much better displacement. Once the well was put online, it achieved an injection rate above expectations, even when the drilled OH interval penetrated significantly less net sands than originally planned. The results on this single well trial seem to corroborate the theory posed, however it is recognized that more data is required to be certain of its results, and that will only come with time, as well performance is measured and compared with other wells that did not use the same technology. The novelty of this new technology is the ability to obtain a better displacement of the OH, leading to a better breaker action and well cleanup in OH completions. Although the trial well was an injector well, the technology is equally applicable to producer wells. The paper will cover the problem description, installation procedures, development and testing of the technology, design aspects of using the technology and the successful implementation in the trial well.

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