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.
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.
Flow assurance in the oil and gas industry refers to the systems put in place to guarantee uninterrupted profitable and sustainable flow of hydrocarbons from the reservoir to surface facilities and ultimately to refineries. Flow assurance challenges include: inorganic scale, asphaltene, wax, corrosion, hydrates, etc. Managing these challenges is becoming more complex because of development of fields under harsher conditions e.g. HPHT reservoirs, sour reservoirs, heavy oil; in addition to further implementation of EOR (gas injection, chemical, surfactant and polymer floods). Different engineering and chemical solutions can be put in place to manage these challenges. All cancellations must be received no later than 14 days prior to the course start date.
This course probes well integrity questions with analytical models embedded in fluid flow and heat transfer principles. Attendees will learn the principles of analytical tools that enable us to diagnose and seek remediation of wellbore safety issues. This one-day training course emphasizes fundamental understanding of fluid- and heat-flow principles leading to improved production operation practices. Beyond those necessary parameters, the input of accurate flowing fluid temperature due to Joule-Thompson effect becomes equally important. To that end, both APB and SCP analyses are discussed.
Understanding the behavior of water-in-crude-oil emulsions is necessary to determine its effect on oil and gas production. The presence of emulsions in any part of the production system could cause many problems such as large pressure drop in pipelines due to its high viscosity. Electrical submersible pumps (ESPs) and gas lift are commonly used separately in lifting crude oil from wells. However, the use of downhole equipment and instruments such as ESPs that cause mixing can result in the formation of an emulsion with a high viscosity. The pressure required to lift emulsions is greater than the pressure required to lift non-emulsified liquids. Lifting an emulsion decreases the pressure drawdown capabilities, lowers production rate, increases the load on the equipment, shortens its life expectancy and can result in permanent equipment damage. Methods and apparatus which reduce the load on the pump, therefore, are desirable. The present paper is directed to understand the behavior of water-in-oil emulsions in artificial lift systems, mainly through gas lift.
Two stable water-in-oil synthetic emulsions were created in the laboratory and their rheology and stability characteristics were measured. One contained crude oil and the other, mineral oil. The second stage included measuring the effect of gas lift exposure on the emulsion behavior and characteristics. The results of the present work indicate that water-in-oil emulsions can be destabilized, and their viscosities lowered under gas exposure. The effect of gas injection on the emulsion was linked to the initial conditions of the emulsion as well as the gas type, injection rate and exposure time.
The present study is directed to methods and systems for combining both ESPs and gas lift for the purpose of improving and simplifying the lift of water-in-oil emulsions from oil wells. The novel methods and apparatus are based on the discovery that by adding gas above the ESPs in the wellbore, the viscosity of an oil-in-water emulsion is actually reduced, thus making it easier to lift oil from the well and extending the life of the ESP. Therefore, in addition to the normal benefits of gas in aiding the lift of liquids, if the gas lift valve is installed at a calculated distance above the pump location, the emulsion viscosity can be reduced. This reduces the load on the ESP.
Gupta, M K (Oil and Natural Gas Corporation Ltd.) | Sukanandan, J N (Oil and Natural Gas Corporation Ltd.) | Singh, V K (Oil and Natural Gas Corporation Ltd.) | Bansal, R (Oil and Natural Gas Corporation Ltd.) | Pawar, A S (Oil and Natural Gas Corporation Ltd.) | Deuri, Budhin (Oil and Natural Gas Corporation Ltd.)
This paper discusses a case study of one of the onshore field of ONGC where while processing well fluid, frequent surge has been observed leading to shutdown of the SDVs creating severe operational problems and loss of production. It was imperative to find out the problematic wells/lines located in clusters which contribute for surge formation and mitigation approach with minimum modifications.
A transient complex network of sixty five wells flowing with a different lift mode such as intermittent gas lift, continuous gas lift etc were developed in a dynamic multiphase flow simulator OLGA. Time cycle of each well were introduced for intermittent lift wells. Simulation study reveals pulsating transient trends of liquid flow, pressure which was matched with the real time data of the plant and hence confirms the accuracy of the model. After verifying the results, different scenarios were created to determine the causes of surge formation. After finding the cause, a low cost approach was considered for surge mitigations.
An integrated rigorous simulation was carried out in OLGA, by feeding more than 12,000 data points to obtain model match. Several scenarios were also created such as optimization of lift gas quantity, optimization of elevation and size. Trend obtained after each scenario was pulsating behaviour and it matched with the real time data appearing in the SCADA system of the field. After rigorous simulation with each scenario, it was established that the cause of surge forming wells/pipelines. Once the root cause of surge has been confirmed then quantum of liquid generated due to surge was determined. Adequacy checks of the existing separators were carried out to estimate the handling capacity of the existing separators at prevalent operating condition. After adequacy check it was found that existing separators cannot handle the surge generated in that time interval leading to cross the high-high safety level, resulting closure of shut down valve (SDV). After establishment of root cause of the surge, a low cost solution with small modification in pipelines and control system/valves was adopted to arrest the surges. It was first of its kind simulation carried out for a huge network of wells/ pipelines by feeding more than 12,000 data to analyze the surge formation cause and capture its dynamism owing to wide array of suspected causes. This will help to address the challenges of efficiently reviewing the entire pipeline network while designing new well pad/GGS and will also help to arrest surge by adopting a low cost solution wherever such situation arises.
Gas lift is one of the most widely used artificial lift methods, and the use of nodal analysis to generate the gas lift performance curve is well established. However, the optimal gas injection rate is often selected as the point with maximum liquid production, which neglects the cost of incremental injection gas volume. This paper investigates the determination of the optimal operational point using a multiobjective optimization technique by considering the trade-off between gas consumption and oil production. The indicator-based evolutionary algorithm transforms the multiobjective problem into a single objective one using the hypervolume metric computed in the objective space. For the gas lift problem, which is a bi-objective problem aimed at maximizing oil production while minimizing gas injection rate, the hypervolume metrics are identically equivalent to geometric hyperareas under the trade-off curve. The optimization is only applied to the monotonically increasing portion of the gas lift performance curve; thus, all trivial sub-optimal conditions are excluded. The optimal operational point of gas injection rate is determined by finding the maximum rectangular hyperarea under the performance curve. The proper determination of the optimal injection gas rate could not only improve the efficiency of the gas lift itself, but also reduce the burden on the maintenance of surface facilities. The method is also applied to the multi-well scenario where a novel multi-well gas lift performance curve is generated using multiobjective Genetic Algorithm, which could help determine the optimal gas allocation/distribution scenario. The described process is incorporated in an integrated workflow which further leads to fast delivery of analysis/results that enable production engineers to make smarter decisions faster in a repeatable way.
Long known for its tolerance of solids-laden fluid and wellbore deviation, gas lift is an increasingly popular artificial lift method for horizontal unconventional wells. A variation of gas lift known as Single Point High Pressure Gas Lift (SPHPGL), noted for the absence of gas lift valves, is now practical because of the availability of high discharge pressure compression equipment.
In SPE 187443 (
When the referenced paper was presented at the October 2017 SPE ATCE, high pressure compressors were not available from industry for lease. This situation changed in early 2018, with rental equipment becoming available in the Permian Basin. Subsequently, a Permian Basin operator (SM Energy) agreed to perform a pilot test in Howard County, Texas to test the conclusions listed in the paper, primarily that Annular SPHPGL could compete rate-wise with ESPs. Plans for a pilot test were made. Additionally, the production facility was modified to handle the possibility of higher flowrates than normally observed with ESPs, as well as increased slugging.
Injection down the tubing with returning flow up the tubing-casing annulus began in September 2018. Initial production rates were close to Nodal Systems Analysis predictions, and comparable with ESP flowrates. This proved that this technique could in fact compete rate-wise with ESPs.
For operators using liquids-rich produced gas for gas lift, the importance of maintaining gas temperatures elevated throughout the compression process is documented. Also, the positive results of the production facility modifications to handle higher flowrates and possible slugging are presented.
Renato P. Coutinho and Paulo J. Waltrich*, Louisiana State University Summary In this paper we describe using a commercial transient multiphase-flow simulator to develop a new operational procedure for liquidassisted gas lift (LAGL) unloading. The simulation model is used in our study to perform sensitivity analysis on the controlling parameters for the LAGL unloading operation. This simulation model is validated with experimental data from field-scale test data presented by Coutinho et al. (2018). From the simulation results and experimental data, it is possible to demonstrate how the injection of a gas/liquid mixture can significantly decrease the injection pressure for unloading operations. Different combinations of injection gas/liquid ratio are numerically tested to evaluate the effect of gas/liquid ratio on the injection pressure during the complete unloading operation. The validated model was used with a newly developed procedure for the complete unloading operation. The modeling results show that using the LAGL technique enabled us to reduce the injection pressure from 1,200 psig, when using single-phase gas in a singlepoint injection system, to approximately 700 psig, when injecting gas/liquid mixtures in a single-point injection system. Analyses on the effect of gas lift valve-orifice size, also presented here, show that using large orifice sizes might reduce the effect of flow friction through the gas lift valve, which directly affects the efficiency of the LAGL unloading operations. As part of the gas lift technique, heavy fluids (e.g., reservoir or completion fluids) need to be lifted out of the casing and production tubing to start or reestablish production. This fluid-removal process is known as wellbore unloading. The kickoff injection pressure is kept low to reduce compression power (Capucci and Serra 1991), which is directly related to the reduction of compressor size and compression cost. Empirical methods are often used to determine the vertical position of the gas lift valves.
Darche, Gilles (Total SA) | Marmier, Rémy (Total SA) | Samier, Pierre (Total SA) | Bursaux, Romain (Total SA) | Guillonneau, Nicolas (Total SA) | Long, Jérôme (Total E&P Congo) | Kalunga, Hernani (Total E&P Angola) | Zaydullin, Rustem (Total E&P Research & Technology USA) | Cao, Hui (Total E&P Research & Technology USA)
We present a global simulation strategy of coupling reservoir and surface network models to manage production profiles of a deep-offshore field (West Africa) operated with a subsea development. This strategy allows a better consolidation of both short-term and long-term production profiles as compared to stacked standalone reservoir profiles.
The simulation study consists of 4 independent reservoir models, connected to surface facilities through a common subsea network. The first method uses loose external coupling between a new-generation commercial reservoir simulator and a commercial subsea network modeling package. It will be used to derive an optimal management of the network (network design, surface controls). This first coupling approach can also generate input data (pressure drops in network described by VLP tables) necessary for the second coupling approach, consisting in a fully coupled reservoir-surface simulator developed in-house, used to evaluate infill scenarios and to compute long-term production profiles.
These two coupling approaches bring their own value to the evaluation of the potential of the field.
The loose external reservoir-network coupling better manages surface constraints. It enables to design and to optimize the subsea network, accounting for the surface capacities. It also manages transient effects in the network, therefore enabling short-term optimization of the production. It will also highlight critical features (like pipe erosion, managed through the C-factor parameter) for the network.
However due to high TCPU and numerical instability, it is unsuitable for extensive sensitivity studies. For that, we use our in-house fully coupled reservoir-network simulator, with network description provided through the external coupling approach. These fully-coupled simulations, though using simpler network descriptions, are much faster and more robust, enabling to perform sensitivities on reservoir management, on infill well scenarios, in order to maximize long-term production profiles. We also developed new options in our in-house simulator to model the critical network features identified by the external coupling approach (like C-factor, fluid mixing, gas-lift optimization on risers).
Therefore, the use of these two workflows has enabled a full optimization of the field development, both The study has shown that these two technical coupling approaches are complementary, and bring better value to a field development when performed together. Furthermore, the external coupling approach identified the critical network features to be also managed in a fully-coupled reservoir-surface simulator, leading to new developments into this simulator (management of C-factor, fluid mixing, gas-lift optimization on risers).
The paper proposes a novel framework for the reservoir and surface facilities modeling. Our new approach benefits from the advantages of the two previous approaches: numerical stability/efficiency of the fully coupled approach and the workflow/accuracy of the separated approach.