This paper describes a trial project to evaluate autonomous inflow control device (AICD) technology to better manage water production in a large heavy oil field in Colombia. The Cajua block is part of the Rubiales field is in the Llanos basin of Eastern Colombia, and has reserves estimated at 7.5 billion barrels. One of the main production challenges is the high water cut, or BSW, driven by strong aquifer flow in the underlying sands of the Carbonera formation. Many wells experience early water break-through and must be produced above 95% BSW for long periods of time. Horizontal wells typically produce up to 8000 barrels per day of total fluid with electric submersible pump (ESP) on cold production, and do not utilize any thermal recovery methods. The loosely-consolidated sandstone reservoir has variable water saturation and permeability, which has continuously frustrated operators'’ attempts to manage water production ever since the Rubiales field was first brought online in the 1980's.
In late 2018, a three well pilot project was initiated to evaluate the ability of inflow control technology to manage water influx at the sandface of the horizontal completions. Three wells in the Cajua block were equipped with AICD screens and swellable packers to evaluate oil production and water cut. The AICD technology works by limiting water inflow based on fluid viscosity. Each segment, or compartment, of the horizontal wellbore is isolated by swellable packers, and the AICD creates a higher or lower drawdown on the reservoir depending on the fluid properties, favoring the inflow of high-viscosity heavy oil over the low-viscosity water.
The early production results show that AICD completions can effectively manage water production by delaying water break-through and restricting water inflow from the reservoir. Each of the three trial wells responded positively to the autonomous ICDs, allowing engineers to produce heavy oil wells more effectively with lower cumulative water volumes.
This project marks the first implementation in South America of AICD technology with rate-controlled production (RCP) valves to manage water production in a heavy oil field. It is also the second application worldwide, after Canada, to show that AICDs can effectively to manage water cut in a heavy oil, cold-production scenario.
Africa (Sub-Sahara) Marathon Oil has produced first gas from its Alba B3 compression platform offshore Equatorial Guinea. The startup enables the company to convert approximately 130 million BOE of proved undeveloped reserves, which more than doubles its remaining proved developed reserve base in the country. Marathon holds an operating interest of about 65% in the field, with Noble Energy holding the remaining stake. Aminex said that gas production from the Kiliwani North-1 well in Tanzania has reached 30 MMcf/D (about 5,000 BOE/D). The project's commissioning process is expected to conclude with a well test to determine the optimal production rate, which previous test data suggest will be approximately 30 MMcf/D, the company said. The operator of the Kiliwani North Development License, Aminex holds a 54.575% interest in the well.
This paper presents the development and implementation of a production and power optimization system supported by a nodal analysis simulation tool and an updated and calibrated multiphase flow hydraulic model.
The workflow implemented in Castilla field identifies operating conditions that may affect the performance of 577 production wells configured in a complex gathering system, managing multiphase flow for heavy oil with low gas oil ratio and high water cut. Initially, this involves the development of a tool for the systematic data transfer from official databases to the simulation model. Furthermore, the hydraulic model was calibrated to reproduce operating conditions. And once the main nodes and boundary conditions at reservoir, wells, network and processing facility were defined, various optimization scenarios were simulated.
With this workflow the field engineers are capable to propose operating changes to increase production taking into consideration network bottlenecks, power consumption, and facilities limitations. The wells with electrical submersible pumps were ranked into the following categories: pump speed variation, well redesign, surface facilities improvement and drawdown limitation. As a result, actions to be implemented in each well were defined. First, ‘pump speed variation’ classified wells quickly demonstrated how the production and power optimization procedure benefit the field. Specifically, it was possible to optimize the extraction process by increasing the oil production up to 10% using power efficiently. Second, several bottlenecks on the network were identified finding atypical pressure drops, using traditional nodal analysis for pressure, temperatures, velocities, and liquid rates calculation per node. Some of them are related to mechanical configuration and others gas accumulation in pipelines. Third, according to the simulation results, a considerable amount of production can be gained and power consumption can be reduced if these conditions are solved.
This workflow contributes to optimize power consumption and enables faster decision-making to efficiently meet the production targets by increasing oil production and reducing water/oil and power/oil ratios.
Mogollon, M. (Frontera Energy) | Arguelles, A. (Frontera Energy) | Rodriguez, A. (Frontera Energy) | Anaya, O. (Ecopetrol) | Miranda, S. (Schlumberger) | Velasquez, E. (Schlumberger) | Villalobos, J. (Schlumberger)
Electric submersible pump (ESP) applications with heavy oil pose substantial technical challenges: decreased pump head capacity, increased power requirements, and poor cooling capacity. This paper shares experiences, lessons learned, equipment standardization exercises, and improvements performed in a field with heavy oil (13º API to 15ºAPI) to extend mean time between failures (MTBF) in more than 3,000 days in a high ESP population with an average of 500 wells. To achieve production goals and extend ESP run life, the project tracks five elements of the ESP life cycle: design, optimization, failure analysis, monitoring, and equipment standardization. As the field evolved, ESPs faced the challenges such as: increased production with increasing water cuts to higher flow rates in horizontal completions with high dogleg severity. Chronological performance of pump mean time between failure is shown before and after improvements. The ESP lifecycle is used as the basis to analyze several factors that caused either total system failure or inability to meet production expectations. This paper explains the implications of each factor and how they affect ESP components, through case studies of representative or repetitive failures and examples of how they were remediating without incurring the expense of oversizing the ESP equipment or completion. This paper shares lessons learned in a five-year, dynamic heavy oil project and includes practical tools to improve ESP run life and optimize well production, which are applicable across the industry and around the world.
Welcome to the SPE Heavy and Extra Heavy Oil Conference--Latin America, in the beautiful city of Medellín, Colombia! This conference assembles the heavy and extra heavy oil community to document our collective knowledge and best practices in the field. You will have the opportunity to enrich your understanding and find ideas to improve productivities and recovery factors of these abundant but challenging reservoirs that encompass more than 60% of the world's oil resources. We have balanced technical-and business-oriented perspectives to accompany the increased attention to viscous oil reservoirs. The aim is to improve skills to develop, produce, transport, and upgrade economically and with energy efficiency the heavy oil and extra heavy oil resources while creating minimal social and environmental impacts.
Peregrino is a field offshore Brazil with a FPSO and 2 fixed platforms currently producing close to 100 000 stb/d of oil. Production wells are equipped with electric submersible pumps (ESP) and all produced water is reinjected back into the reservoir using 6 injectors for pressure support. The viscosity of the crude is high (163 cp at reservoir conditions). The present work explores the merits and provides the development details of a model-based production optimization scheme to advice on the best frequency settings of the ESPs in each well. This to ensure the maximum amount possible of oil is produced when water injection capacity is a bottleneck. Furthermore, it studies how the optimal operating conditions change with time.
The optimization formulation considers maximization of total oil production, the maximum allowable water produced given by the available injection capacity and the operational constraints of the ESPs. The optimization was formulated as a Mixed-Integer Linear Problem (MILP). The performance of the wells is represented with piecewise linear tables generated from a commercial simulator.
For the cases tested, the proposed optimization scheme works successfully: It has low running times suitable for real time production optimization, handles successfully multiple operational constraints, and guarantees global optimality. Optimization results are presented for future times.
By using piecewise linear tables to represent the well performances the fidelity of the original model is maintained, while ensuring a robust and fast optimization of the problem. Moreover, it is suitable for frequent model updates without requiring changing the optimization formulation. In summary, this work proposes a method to handle part of the operational complexities of the Peregrino field using a digital twin.
Oil and gas production systems are complex and usually consist of several production elements and corresponding models: (1) reservoirs modelled with reservoir simulators using geological and fluid data, (2) wells and surface production networks modelled with flow assurance applications, (3) surface processing facilities modelled in process simulators and (4) economic models. The traditional approach ("silo" approach) consists of modelling each part of the system independently from the others without considering upstream and/or downstream interactions. Integrated Asset Modelling (IAM) is a maturing solution incorporating effects of all the elements of an asset. This paper shows the benefits of successful IAM implementations in four highly complex and technically challenging assets around the globe.
IAM aims to bring together all models of the value chain, from the reservoir to the point of sales. It enables us to perform numerous sensitivity analysis by changing any parameter across the value chain and investigate its influence on the entire system. The presentation concludes with guidelines and best practices for IAM implementation. It especially focuses on three very important issues faced when dealing with IAM: (1) software and model integration, (2) PVT consistency across the value chain and (3) optimization.
Several case studies from the industry are used as illustration: diluent injection optimization for a heavy oil field in the North Sea, integration of reservoir and process models for a complex offshore multi-field asset in Indonesia, production allocation for an onshore multi-field asset in South America and API blending optimization for a multi-field asset in Middle East. The different case studies show that benefits of implementing an IAM approach can be significant and immediate: higher production, lower OPEX or better information for further CAPEX.
In the current market situation, IAM approach is a cost-effective solution to optimize oil and gas production. By bringing together existing information and models from all parts of the production system, IAM breaks barriers between disciplines and enables an asset-scale overview that leads to more informed decision-making and ultimately higher profits for operators.
AbstractApplying proven technology to control the production of water and gas has become necessary to extend the life of very light-oil reservoirs while optimizing economics. Traditional inflow control devices (ICDs) can help balance the flow of oil, but are not helpful once water and gas breakthrough occurs. Multiphase data and field-evaluation applications show that low-viscosity, fluidic-diode, autonomous ICDs (AICDs) support the production of very light oil while restricting gas and water.Testing has proven that the low-viscosity, fluidic-diode AICD can differentiate oil from water and gas, even very light oils. Tool performance was characterized by measuring the pressure differential vs. the flow rate of diverse oil viscosities representing very light-oil formations in Canada, Russia, Malaysia, and Brazil. The AICD was flow tested with very light oils, water, and gas, as well as multiphase testing simulating mixtures of oil/water for different water cuts and oil/gas at diverse gas-volume fractions. The characterization of flow performance was embedded into sophisticated reservoir simulators for steady and transient evaluations.The multiphase condition of the test fluids was achieved by increasing water cuts and gas-volume fractions. The flow performance tests indicated that the highly sensitive fluidic sensor of the low-viscosity AICD enhances the production of very light oil and restricts water and gas as the water cut and gas-volume fraction increase. The restriction process gradually increases as per the water and gas ratio in the mixture and is reversible if water and gas production recede. Comparisons of the low-viscosity, fluidic-diode AICD vs. a traditional ICD show approximately 25% less water production and 40% less gas production with the AICD. The ability of the low-viscosity AICD to produce very light oils while restricting the flow of gas and water extends the life of light-oil reservoirs by increasing the production of hydrocarbons while helping to lower costs.For optimum reliability, this unique fluidic-sensor technology has no moving parts or control lines, but uses fluid dynamics to distinguish fluids. Multiphase-flow performance testing and field simulation of light-oil reservoirs indicate that the low-viscosity, fluidic-diode AICD favors the production of light oil (0.3 cP–1.5 cP) and restricts the flow of gas and/or water in a multiphase production-flow environment.
In heavy oil fields, well longevity is limited by water inflow. Passive inflow control devices (ICDs) are effective in terms of balancing production flow and delaying the onset of water production. Nevertheless, when gas and/or water breakthrough occurs, a passive ICD enables production of the unwanted fluid. Autonomous ICDs can provide additional restriction to the unwanted fluids and can further enhance the production of oil.
The fluidic diode autonomous ICD is functionally based on fluid dynamics technology in which internal geometry directs flow movement based on the viscosity of the fluid. The autonomous ICD enhances oil production while restricting water and gas influx, without the requirement of intervention or moving parts within the device. The result is improved sweep efficiency, which can extend well life and thereby assist in reducing operating costs. Effective design of an autonomous ICD completion is aided with an accurate prediction of the flow behavior through the device. This paper describes flow testing and field performance of a fluidic diode autonomous ICD optimized for the production of very heavy oils with a viscosity above 150 centipoise (cp), while restricting water and gas production.
The test results of the autonomous ICD demonstrate that the fluidic diode can produce more oil while restricting water. In fact, heavy oil can flow at a higher rate with less pressure drop than water. Flow performance of this device has been characterized by measuring the pressure drop versus the flow rate at differing viscosities, confirming that the autonomous ICD effectively restricts undesired fluids, while enhancing the production of oil. Numerical simulations demonstrate an improvement of water reduction by more than 50% compared to standalone screen completions. This technology has been used to promote oil production and restrict water influx in fields where the oil viscosity is greater than 700 cp. This paper also demonstrates the appropriate design philosophy when determining the suitable application of the technology to help maximize oil recovery and minimize water production.
Fluid flow performance is what truly distinguishes the autonomous ICD from other devices. This fluidic diode autonomous ICD is a robust, reliable solution with no moving parts, nor the requirement of intervention of any kind. Its predictable flow performance has been proven through testing, modeling, and field application.