Hybrid Electrical-Submersible-Pump/Gas-Lift Application to Improve Heavy Oil Production: From System Design to Field Optimization

2021 ◽  
pp. 1-28
Author(s):  
Son Tran ◽  
Vu Le
Keyword(s):  
Service Life ◽  
Power Consumption ◽  
Heavy Oil ◽  
Oil Production ◽  
Production Optimization ◽  
Submersible Pump ◽  
Hybrid Mode ◽  
Field Development ◽  
Electrical Submersible Pump ◽  
Gas Lift

Abstract The typical challenge encountered in developing heavy-oil reservoirs is inefficient wellbore lifting caused by complex multiphase flows. The literature on modeling of a hybrid artificial lift (AL) system is relatively sparse and these works typically model the AL system on the basis of individual AL methods. This paper presents a case study of the design and optimization of a hybrid AL system to improve heavy-oil production. We systematically design and model a hybrid electrical-submersible-pump/gas-lift (ESP/GL) system to enhance wellbore lifting and production optimization. We found that the implementation of hybrid ESP/GL system provides the flexibility to boost production and reduces production downtime. Results from the pilot test show that the production rate in hybrid mode is approximately 30% higher than in ESP-only mode. The power consumption of the hybrid mode is 3% lower in the ESP-only mode. Furthermore, the average ESP service life exceeds six years which is better than expected in the field development plan. The pump-performance-curve model is built with corrections for density and viscosity owing to the increased water production. We observed a higher pressure drawdown with GL injection at fixed ESP frequency. The GL injection reduces the density of the fluid column above the ESP, resulting in less pressure loss across the pump, less power consumption, and potentially extended service life. The nodal-analysis results suggest that the pump capacity can be considerably expanded by manipulating the GL rate instead of increasing the frequency.

Pushing 30 Years Multiple Brown Fields Limits Through Artificial Lift and Facilities Improvement

2021 ◽  
Author(s):  
Mohd Hafizi Ariffin ◽  
Muhammad Idraki M Khalil ◽  
Abdullah M Razali ◽  
M Iman Mostaffa
Keyword(s):  
New Technology ◽  
Lessons Learned ◽  
Oil Fields ◽  
Submersible Pump ◽  
Large Space ◽  
Gas Well ◽  
Wellhead Pressure ◽  
Artificial Lift ◽  
Electrical Submersible Pump ◽  
Gas Lift

Abstract Most of the oil fields in Sarawak has already producing more than 30 years. When the fields are this old, the team is most certainly facing a lot of problems with aging equipment and facilities. Furthermore, the initial stage of platform installation was not designed to accommodate a large space for an artificial lift system. Most of these fields were designed with gas lift compressors, but because of the space limitation, the platforms can only accommodate a limited gas lift compressor capacity due to space constraints. Furthermore, in recent years, some of the fields just started with their secondary recovery i.e. water, gas injection where the fluid gradient became heavier due to GOR drop or water cut increases. With these limitations and issues, the team needs to be creative in order to prolong the fields’ life with various artificial lift. In order to push the limits, the team begins to improve gas lift distribution among gas lifted wells in the field. This is the cheapest option. Network model recommends the best distribution for each gas lifted wells. Gas lifted wells performance highly dependent on fluid weight, compressor pressure, and reservoir pressure. The change of these parameters will impact the production of these wells. Rigorous and prudent data acquisitions are important to predict performance. Some fields are equipped with pressure downhole gauges, wellhead pressure transmitters, and compressor pressure transmitters. The data collected is continuous and good enough to be used for analysis. Instead of depending on compressor capacity, a high-pressure gas well is a good option for gas lift supply. The issues are to find gas well with enough pressure and sustainability. Usually, this was done by sacrificing several barrels of oil to extract the gas. Electrical Submersible Pump (ESP) is a more expensive option compared to a gas lift method. The reason is most of these fields are not designed to accommodate ESP electricity and space requirements. Some equipment needs to be improved before ESP installation. Because of this, the team were considering new technology such as Thru Tubing Electrical Submersible Pump (TTESP) for a cheaper option. With the study and implementation as per above, the fields able to prolong its production until the end of Production Sharing Contract (PSC). This proactive approach has maintained the fields’ production with The paper seeks to present on the challenges, root cause analysis and the lessons learned from the subsequent improvement activities. The lessons learned will be applicable to oil fields with similar situations to further improve the fields’ production.

Artificial Intelligence Assisted Well Portfolio Optimization - An Automated Reservoir Management Advisory System to Maximize the Asset Value - Case Study from ADNOC Onshore

2021 ◽  
Author(s):  
Subba Ramarao Rachapudi Venkata ◽  
Nagaraju Reddicharla ◽  
Shamma Saeed Alshehhi ◽  
Indra Utama ◽  
Saber Mubarak Al Nuimi ◽  
...  
Keyword(s):  
Machine Learning ◽  
Hybrid Approach ◽  
Simulation Models ◽  
Production Optimization ◽  
Added Value ◽  
Risk Scores ◽  
Well Performance ◽  
Field Development ◽  
Advisory System ◽  
Gas Lift

Abstract Matured hydrocarbon fields are continuously deteriorating and selection of well interventions turn into critical task with an objective of achieving higher business value. Time consuming simulation models and classical decision-making approach making it difficult to rapidly identify the best underperforming, potential rig and rig-less candidates. Therefore, the objective of this paper is to demonstrate the automated solution with data driven machine learning (ML) & AI assisted workflows to prioritize the intervention opportunities that can deliver higher sustainable oil rate and profitability. The solution consists of establishing a customized database using inputs from various sources including production & completion data, flat files and simulation models. Automation of Data gathering along with technical and economical calculations were implemented to overcome the repetitive and less added value tasks. Second layer of solution includes configuration of tailor-made workflows to conduct the analysis of well performance, logs, output from simulation models (static reservoir model, well models) along with historical events. Further these workflows were combination of current best practices of an integrated assessment of subsurface opportunities through analytical computations along with machine learning driven techniques for ranking the well intervention opportunities with consideration of complexity in implementation. The automated process outcome is a comprehensive list of future well intervention candidates like well conversion to gas lift, water shutoff, stimulation and nitrogen kick-off opportunities. The opportunity ranking is completed with AI assisted supported scoring system that takes input from technical, financial and implementation risk scores. In addition, intuitive dashboards are built and tailored with the involvement of management and engineering departments to track the opportunity maturation process. The advisory system has been implemented and tested in a giant mature field with over 300 wells. The solution identified more techno-economical feasible opportunities within hours instead of weeks or months with reduced risk of failure resulting into an improved economic success rate. The first set of opportunities under implementation and expected a gain of 2.5MM$ with in first one year and expected to have reoccurring gains in subsequent years. The ranked opportunities are incorporated into the business plan, RMP plans and drilling & workover schedule in accordance to field development targets. This advisory system helps in maximizing the profitability and minimizing CAPEX and OPEX. This further maximizes utilization of production optimization models by 30%. Currently the system was implemented in one of ADNOC Onshore field and expected to be scaled to other fields based on consistent value creation. A hybrid approach of physics and machine learning based solution led to the development of automated workflows to identify and rank the inactive strings, well conversion to gas lift candidates & underperforming candidates resulting into successful cost optimization and production gain.

Experimental Study and Modeling of Heating Effect in Electrical Submersible Pump Operating With Ultra-Heavy Oil

2018 ◽  
Author(s):  
Jorge Luiz Biazussi ◽  
Cristhian Porcel Estrada ◽  
William Monte Verde ◽  
Antonio Carlos Bannwart ◽  
Valdir Estevam ◽  
...  
Keyword(s):  
Heavy Oil ◽  
Critical Factor ◽  
High Viscosity ◽  
Inlet Temperature ◽  
Outlet Temperature ◽  
Heating Effect ◽  
Submersible Pump ◽  
Oil Viscosity ◽  
Artificial Lift ◽  
Electrical Submersible Pump

A notable trend in the realm of oil production in harsh environments is the increasing use of Electrical Submersible Pump (ESP) systems. ESPs have even been used as an artificial-lift method for extracting high-viscosity oils in deep offshore fields. As a way of reducing workover costs, an ESP system may be installed at the well bottom or on the seabed. A critical factor, however, in deep-water production is the low temperature at the seabed. In fact, these low temperatures constitute the main source for many flow-assurance problems, such as the increase in friction losses due to high viscosity. Oil viscosity impacts pump performance, reducing the head and increasing the shaft power. This study investigates the influence of a temperature increase of ultra-heavy oil on ESP performance and the heating effect through a 10-stage ESP. Using several flow rates, tests are performed at four rotational speeds and with four viscosity levels. At each rotational speed curve, researchers keep constant the inlet temperature and viscosity. The study compares the resulting data with a simple heat model developed to estimate the oil outlet temperature as functions of ESP performance parameters. The experimental data is represented by a one-dimensional model that also simulates a 100-stage ESP. The simulations demonstrate that as the oil heat flows through the pump, the pump’s efficiency increases.

scholarly journals Modelling and Robustness Analysis of Model Predictive Control for Electrical Submersible Pump Lifted Heavy Oil Wells

2016 ◽  
Vol 49 (7) ◽  
pp. 544-549 ◽  
Author(s):  
Dinesh Krishnamoorthy ◽  
Elvira M. Bergheim ◽  
Alexey Pavlov ◽  
Morten Fredriksen ◽  
Kjetil Fjalestad
Keyword(s):  
Model Predictive Control ◽  
Predictive Control ◽  
Heavy Oil ◽  
Robustness Analysis ◽  
Oil Wells ◽  
Submersible Pump ◽  
Electrical Submersible Pump

Subsea Oil and Gas Production Assurance Using Artificial Lifts and Nodal Analysis

2015 ◽  
Author(s):  
Ikenna A. Okaro ◽  
Longbin Tao
Keyword(s):  
System Analysis ◽  
Oil And Gas ◽  
Oil Production ◽  
Gas Production ◽  
Submersible Pump ◽  
Oil And Gas Production ◽  
Nodal Analysis ◽  
Multiphase Pump ◽  
Electrical Submersible Pump ◽  
The Impact

This paper describes how the operation of deep, subsea oil wells can be analyzed and optimized using artificial lift systems. A modest explanation was offered about an enhanced Hubbert model for determining production targets at pre-feed phase of project. In addition, the impact of artificial lifts on the economics of subsea wells facing hyperbolic production decline was illustrated. The principle of Nodal analysis was highlighted and applied to optimize a proposed subsea oil production case. Configurations of a nominally rated rod pump, a multiphase pump and an electrical submersible pump were modelled in a steady-state flow using Pipesim software and the simulated results which were functions of liquid flow rate and pressure distribution across the production system exposed the behavior of the system. The results showed that over 100% volumetric efficiency was achieved using a combination of electrical submersible pump at the bottom hole and a multiphase pump at riser base. A guide is presented on how to predict, analyze and enhance the recovery curve of subsea oil production using artificial lifts and nodal-system analysis. The benefit of this work is an enabling cost-effective approach for ensuring production assurance in deep water oil and gas production.

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