An Investigation Into the Need of a Dynamic Coupled Well-Reservoir
Simulator

Alberts, Garrelt; Belfroid, S.P.C.; Peters, Lies; Joosten, Gerard

doi:10.2523/110316-ms

Cited by 5 publications

(2 citation statements)

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“…(Grubert, Wan et al 2009) showed that the impact of completion design in the long-term well performance is not correctly achieved without two tier coupling between well and reservoir. (Alberts, Belfroid et al 2007) analyzed the dynamic behavior in the well and reservoir identifying the time and space scales at which the well-reservoir coupling becomes important. In The zonal pressure response for all PDGs is about the same and the differences observed happen due to friction losses.…”

Section: Iw Monitoring System Design Examplementioning

confidence: 99%

“…Os resultados mostraram aumento da eficiência quando comparados com o estado da arte e um potencial para capturar a influência mútua entre os processos de produção. (Alberts, Belfroid et al 2007) Figure 4.2 -Sensors positions and their response in a producing horizontal well (Valiullin, Ramazanov et al 2009) Figure 4.3 -Zonal intelligent well transient pressure response (Muradov and Davies 2012). Table 3.1 -Seismic sensors comparison by technology.…”

Section: Introductionunclassified

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Intelligent Well Transient Temperature Signal Reconstruction

SILVA¹

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Section: Iw Monitoring System Design Examplementioning

confidence: 99%

Section: Introductionunclassified

Intelligent Well Transient Temperature Signal Reconstruction

SILVA¹

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Gas Coning Control for Smart Wells

Leemhuis¹,

Belfroid²,

Alberts³

2007

SPE Annual Technical Conference and Exhibition

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A strong increase in gas influx due to gas coning and the resulting bean-back because of Gas to Oil Ratio (GOR) constraints can severely limit oil production and reservoir drive energy. The purpose of this paper is to demonstrate that oil production after a gas breakthrough can be optimized by means of an inflow control strategy that takes the effects of 'natural gas lift' and production choking into account. Within the research framework of the "Integrated System Approach Petroleum Production" (ISAPP) knowledge center of TNO, TU Delft and Shell, it has been shown that this optimization can be achieved by controlling the location and amount of gas influx in a horizontal smart well. In order to show a proof of principle we have implemented a PID feedback controller, which controls the gas fraction in a well by changing its Inflow Control Valve (ICV) settings, on a test case in a dynamic reservoir simulator. We introduce a three step strategy for production optimization: firstly we model how the controlled production rate after breakthrough depends on the gas fraction; secondly we will determine the optimal gas fraction; thirdly we will consider the capability of a PID controller to produce at this optimal gas fraction. Simulation experiments show that a PID controller is an effective means to prevent a full gas breakthrough and, moreover, can be used to increase the produced oil rate by tuning ICV settings to an optimal gas fraction. These experiments also demonstrate the benefits of using downhole ICV control in comparison to wellhead control. In current operations ICVs are mostly used to completely shut down well segments that experience gas coning. We show that by keeping these ICVs open in a controlled way the, otherwise undesirable, phenomenon of gas coning can be used to optimize oil production. Introduction: Gas Coning Gas coning is a phenomenon where the gas-oil-contact (GOC) of a reservoir slowly moves towards a well as a result of oil drawdown. In case of horizontal or deviated wells this is often a zonal phenomenon, which occurs at a limited amount of perforations only, and is referred to as 'cresting' (Figure 1). At a certain moment in the production life of a gas coning well the gas-oil-contact will reach the well and a gas breakthrough will occur. Upon breakthrough the well will experience a high gas influx. Largely for three reasons this is an undesired phenomenon. Firstly because the gas phase may start to dominate production, which will deem the well to be uneconomical. Secondly, the influx of gas may damage topside equipment that is not designed to process large quantities of this phase. Thirdly, after breakthrough the gas cap of the oil reservoir will be depleted fast, taking away its drive energy.

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Numerical Modeling of Fully-Transient Flow in the Near-Wellbore Region During Liquid Loading in Gas Wells

Zhang

Falcone

Teodoriu

2009

Latin American and Caribbean Petroleum Engineering Conference

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In oil and gas field operations, the dynamic interactions between reservoir and wellbore cannot be ignored, especially during transient flow in the near-wellbore region. A particular instance of transient flow in the near-wellbore region is the intermittent response of a reservoir that is typical of liquid loading in gas wells. Despite the high level of attention that the industry has devoted to the alleviation of liquid loading, the fundamental understanding of the associated phenomena is still surprisingly weak. This applies not only to the flows in the wells, but also to the ways in which these flows interact with those in the reservoir. The classical way of dealing with these interactions, inflow performance relationships (IPRs), relate the inflow from the reservoir to the pressure at the bottom of the well, which is related to the multiphase flow behavior in the tubing. These relationships are usually based on steady-state or pseudo steady-state assumptions. However, such IPRs may be inadequate when a transition from an acceptable liquid loading regime to an unacceptable occurs over a relatively small range of production rates and, hence, over a relatively short time. The most satisfactory solution would be to couple a transient model for the reservoir to a transient model for the well. This paper presents the results of a numerical modeling effort focused on the identification of the transient pressure profile in the near-wellbore region during fully transient flow conditions. The preliminary results, obtained for a single-phase (gas) situation and for a three-phase (oil-water-gas) situation, show a "U-shaped" pressure profile along the reservoir radius. The existence of a similar pressure profile could be the explanation for the reinjection of the heavier phase into the reservoir during liquid unloading in gas wells. Introduction Liquid loading in gas wells is one of the particular instances of transient flow in both the wellbore and the near-wellbore region. Liquid loading occurs when the reservoir pressure decreases in mature gas fields and the liquid content of the well and its particular distribution at the given instant in time create a backpressure that restricts, and in some cases even stops, the flow of gas from the reservoir. Liquid loading is an all too common problem in mature gas fields around the world. In the USA alone at least 90% of the producing gas wells encounter such problems, at least occasionally. Such is the importance of liquid loading that the industry has devoted a lot of attention to the alleviation of the problem using various measures. However, the fundamental understanding of the associated phenomena is still surprisingly weak. This applies not only to the flows in the wells, but also to the ways in which these flows interact with those in the reservoir. The classical way of dealing with these interactions is through inflow performance relationships (IPRs) where the inflow from the reservoir is related to the pressure at the bottom of the well, which is related to the multiphase flow behavior in the well (and in the rest of the production system, if appropriate). The latter is also usually calculated from steady-state relationships (though these often lack a fundamental basis). However, a transition from an acceptable liquid loading regime to an unacceptable one may occur over a relatively short time. Flow at the surface will remain in mist or annular flow regime till the conditions change sufficiently to exhibit characteristics of phenomena transitional flow. At this point, the well production becomes somewhat erratic, progressing to slug and churn flow, while following an overall decreasing trend. As a result, the liquids start to dynamically accumulate in the wellbore, causing downhole pressure fluctuations. The increasing liquid holdup augments the backpressure on the formation, which ultimately accounts for the well's death.

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An Investigation Into the Need of a Dynamic Coupled Well-Reservoir Simulator

Cited by 5 publications

References 0 publications

Intelligent Well Transient Temperature Signal Reconstruction

Intelligent Well Transient Temperature Signal Reconstruction

Gas Coning Control for Smart Wells

Numerical Modeling of Fully-Transient Flow in the Near-Wellbore Region During Liquid Loading in Gas Wells

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