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.
Liquid loading phenomenon is known as the inability of the produced gas to carry all the co-produced liquid to the surface. Under such condition, the non-removed liquid accumulates at the wellbore resulting in reduction of the production and sometimes cause the death of the well. Several studies were carried out and correlation were developed based on field and experimental data with the aim to predict the onset of liquid loading in a gas well. However, each model provides different indication on the critical gas velocity at which the liquid loading exists. Thus, to have a clear understanding on the difference between most used models, experiments were performed in an upward inclinable pipe section. The 60-mm diameter test pipe was positioned at angles of 30°, 45° and 60° from horizontal. The fluids used were air and light oil. Measurements include fluid velocities and fluid reversal point. High-speed video cameras were used to record the flow conditions in which the onset of liquid loading initiated. Experimental results were compared with existing models by
This study presents a methodology to define the most-adequate artificial-lift technique on the basis of technical limitations, a suitability coefficient (based on an attributes table), and economic analysis toward horizontal well configuration. This paper presents an artificial-lift selection process to maximize the value of unconventional oil and gas assets. This paper focuses on a fit-for-purpose methodology to evaluate well-production performance for a wide range of artificial-lift techniques.
Installing an inappropriate or poorly specified ESP leads to lost production, short runlives, and ultimately higher production costs. With the growth in ESP-produced unconventional wells, appropriate ESP design becomes more challenging due to divergent HP and head requirement at initial production versus the depleted well at end of life. ESP design is typically performed by the ESP vendors (often with less than complete design data), reviewed by the production engineer, and then equipment selected and installed. The "Why?" and the "How?" of the design What well, production & facilities information is required to ensure a successful design Function and operation of each ESP component and how it impacts the application design Calculations and data that make up an effective ESP design ESP application design by hand and using software Single operating point and dual operating point designs Gas handling approaches with ESPs – functional limits Reviewing ESP designs – how to read the report ESP equipment specifications This course will empower Production Engineers to understand the correct equipment sizing for a well and enable the engineer to quality check the design report provided by the vendor. Upon completion of this course, participants will be able to perform a design and read a design report, comment on its applicability to the well’s operation, and know if the specified equipment will meet the well requirements.
Unconventional production patterns in the Permian Basin are leading producers to replace electrical submersible pumps (ESPs) with gas lift, which had been little used there. When a gas lift system starts performing poorly, there is a good chance no one will notice. It is not an event that demands attention like a broken pump. A gas lift system will continue injecting gas into wells and oil will continue to come out. Just not as much oil as there could be.
An experimental study was conducted by use of a 6-in.-inner-diameter Onshore gas developments are often characterized by drilling, fracturing, and production of wells before low-pressure gas-gathering systems are in place. As well production declines, liquid-loading issues begin to appear. Use of a twin-screw pump to boost deliquefication was investigated.
We don’t include a structure like the Eiffel Tower with separators, pumps, and compressors on the top observation platform in an onshore development plan. And yet, how many jacket platforms are there around the world? Production from an offshore Angola field has been decreasing because of subsea pressure declines amid water-cut increases and limited gas compressor capacity. The development process leading to the selection of high-boosting multiphase pumps is described. In maturing oil wells, oil production is often restricted as reservoir pressure depletes.
PipeFractionalFlow, a spinoff startup from the University of Texas at Austin, uses new theories and equations to make modeling complex multiphase flow more affordable. A model recently developed offers operators an “independent and unbiased” way to validate the system and select candidate wells. Slug flow has made the life of an unconventional production engineer a bit complicated, but a new downhole technology may smooth things right out by solving some big artificial lift problems for the shale sector. This paper presents the results of a comprehensive multiphase-flow study that investigated the relationship between the principal stresses and lateral direction in hydraulically fractured horizontal wells. This work experimentally investigates the behavior of an intermittent multiphase liquid/gas flow that takes place upstream of an electrical submersible pump (ESP).
ExxonMobil’s hot streak of offshore discoveries have sparked investor interest in the Guyana-Suriname basin. How did the company get there, and why do industry representatives feel optimistic about future deepwater prospects in the region? In the 30 years of operations on Suriname’s Tambaredjo field, the prime mechanism for lifting the 15.6 °API crude to surface has been that of progressing cavity pumps (PCPs).
This paper describes numerical-simulation results from a three-well pad in a stacked liquids-rich reservoir (containing gas condensates) to understand the interaction between wells and production behavior. This study presents a methodology to define the most-adequate artificial-lift technique on the basis of technical limitations, a suitability coefficient (based on an attributes table), and economic analysis toward horizontal well configuration.