Transient Multiphase-Flow Simulation Enables Slugging Mitigation Solution
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The complete paper discuses a well with a history of sand production that exhibits long cyclic slugging behavior. Whether the slugging is caused by the gap at the well’s lower completion, by sand transportation, or by both is not fully understood. Dynamic wellbore modeling with sand-particle transport is essential in modeling the complex slugging behavior. Transient simulations successfully produced the slugging behavior observed in the field. Cyclic slugging was determined to be caused by the flow dynamics generated by particles of small to medium size.
Well X1 exhibited long cyclic slugging behavior, as seen from the tubinghead pressure (THP) and downhole pressure measured for 1 month (i.e., 0 to 30 days) (Fig. 1). Surface rate measurements from the rate test are available for 1 week (i.e., from Days 23 to 30); these are shown in Fig. 1 along with downhole pressure. For this period, downhole pressure decline is observed as the rate builds. The objective of this analysis is to understand the long cyclic slugging behavior of the well by analyzing and simulating historical production data and to arrive at a potential mitigation solution.
The multiphase-flow model incorporated in the commercial transient multiphase simulator used in this study is based on first principles whereby the equations of mass, momentum, and energy are solved in time and space to arrive at temporal and spatial variations of phase fractions, velocities, pressure, and temperature. These mass, momentum, and energy equations are solved rigorously in the transient multiphase simulator model with the appropriate closure laws defining interfacial and wall friction, deposition and entrainment of droplets, and bubble entrainment. The model is suited to well-simulation applications because it can simulate complex trajectories, smart completions, and the transient heat transfer in wells by accounting for all the applicable modes of heat transfer (conduction, convection, and radiation) between the tubing, casing, and formation. The model is capable of handling sand-particle transport.
The fluid is characterized in a pressure/volume/temperature package using the Soave-Redlich-Kwong equation of state. The well extends to a true vertical depth of 9,635 ft, corresponding to a measured depth of 13,162 ft rotary table elevation. There is a 2,000-ft gap between the mule shoe and the packer, where the fluid flow is exposed to the 7-in. liner. The various restrictions to flow, such as the tubing-retrievable, surface-controlled, subsea safety valve and nipple, were considered in the wellbore modeling.
For the initial stage, inflow from the reservoir to the wellbore is modeled using a lumped linear productivity index (PI) at the top of the perforation at 12,257 ft measured depth. For Stage 2 modeling, two zones were included in the model and sand inflow was considered mainly from the upper zone. For reservoir inflow, a range in liquid PI from 0.5 to 1.4 STB/D/psi was considered. Reservoir temperature and pressure were 210°F and 5,782 psia, respectively. The analysis covers sand-particle size ranging between D10, D50, and D90 size as 36.22, 265.9, and 591.3 µm, respectively, based on the available sand-size-distribution information. Sand-particle densities of 2650 and 2100 kg/m3 were considered.
Stage 1: Lumped Inflow Without Sand Transport
The gap between the mule shoe and the packer, which is exposed to the 7-in. liner, is believed to be a possible cause of liquid accumulation in cycles and may produce the observed slugging behavior. From the simulation, unstable flow with small fluctuations was observed, which does not match the pattern of long cyclic slugs observed in the field. The average bottomhole pressure (BHP) is significantly lower than field-measured BHP, possibly because of the absence of sand in the fluid column, which is not considered in the present analysis.
Stage 2: Inclusion of Zone With Sand Production at High Drawdown
In the second stage, the model built in the first stage was extended to include inflow from contributing layers, which were represented by their respective inflow models. Constant reservoir pressure of 5,782 psia was considered for both the zones. Sand particles were assumed to be produced from the reservoir at high drawdown. In reality, the large-diameter particles (D90 or higher) would be immobile at the gap between the mule shoe and the packer at the current operating rates. The transient multiphase-flow simulator can only handle a single-diameter particle for a particular simulation. As a workaround, larger-diameter sand particles, which are not mobile at current rates, are assumed to occupy the gap between the mule shoe and the packer and, therefore, reduce the effective diameter of the gap.
This analysis was conducted on several combinations of sand-particle sizes, sand-particle densities, and PI values. For each combination of sand-particle density and PI, certain particle sizes resulted in slugging dynamics similar to those observed in the field with particles being immobile or less mobile at low to medium rates, and mobile at higher rates during the slugging cycle. Choosing a larger-diameter particle would result in immobility leading to permanent particle blockage because the particles would accumulate and would not be produced. On the other hand, choosing a very-small-diameter particle causes the particles to be produced at the wellhead without causing slugging. The complete paper provides a detailed discussion of the slugging cycle, elaborated upon in Fig. 6 of the complete paper.
On the basis of the study’s findings, the cyclic slugging mechanism is better understood and is explained by the following process:
- Production declines as the particle gradually builds up, leading to a packed state with small flow through the porous blockage (35% porosity was used in simulations).
- BHP builds up as the pressure behind the blockage builds up, which is gradually transferred downstream because of porous blockage.
- Particles slowly move up the tubing at medium rate (200 to 250 Sm3/d liquid) but are still not produced; thus, BHP is relatively high.
- BHP falls because of reduced head as particles are eventually produced (also, increasing THP indicates increased flow rate).
- Fresh particles are produced from the reservoir at increased drawdown at higher rates of approximately 400 Sm3/d liquid).
- BHP falls further as the blockage builds up. Thus, for the downstream section where the gauge is located, flow is disconnected gradually with the upstream section of the blockage, with pressure drop across the blockage and rate gradually falling.
Several simulations were conducted with a commercial multiphase transient simulator for Well X1, which exhibits long cyclic slugging behavior. A scenario accounting for flow from both the zones at constant PI and sand production at high drawdown predicts slugging behavior very similar to that observed in the field. Cyclic slugging is believed to be caused by the flow dynamics generated by particles of small to medium size. Slugging is a result of complete blockage by particles at the gap between the mule shoe and the packer and subsequent pressure buildup behind to gradually release the blockage. The particle bed is not mobile at low rates (50 to 100 Sm3/d), moves very slowly to the 4.5-in. tubing section at medium rates (200 to 250 Sm3/d), and eventually produces out of the tubing at higher rates (400 to 450 Sm3/d). Fresh particles are produced from the reservoir at increased drawdown, and the cycle repeats itself. Measured data from the sand detector confirm the production of sand, particularly around the period of high THP (or high drawdown), which is also predicted by simulation.
Potential slugging-mitigation solutions could include higher flow velocity [achieved by reducing the gap size at the lower completion section together with either tubing-size reduction or electrical-submersible-pump (ESP) installation] or implementing an appropriate sand-control or sand-consolidation method. Reducing the tubing size and the gap between the mule shoe and the packer (for both 3-in. or 2.441-in. inner diameter) could be a potential solution because the well would able to lift larger-diameter particles than the ones that the well produces from the sandface in cycles. Reduction of the gap between the mule shoe and the packer to 4-in., in combination with ESP installation, could be another potential solution. The ESP should be able to deliver a liquid rate of 1115 Sm3/d to ensure continuous lifting of D90-size particles (591.3 µm) being produced from the reservoir. Also, successful implementation of a sand-control or sand-consolidation method could lead to significant improvement in well production with the current well design, assuming that any existing sand in the 2,000-ft gap section could be cleaned up. However, considering the high cost and risk factor, no future workover is planned.
Transient Multiphase-Flow Simulation Enables Slugging Mitigation Solution
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