Innovative Gas Lift in Heavy Oil Wells: Case Study in Block 6, Sudan
- Tang Xueqing (Petroenergy) | Li Guocheng (Petroenergy) | Fahmi Abdalla Alawad (Petroenergy) | Yu Keqiang (Petroenergy) | Cai Bo (Petroenergy) | Tagwa Ahmed Musa (Sudan University of Science and Technology)
- Document ID
- Society of Petroleum Engineers
- North Africa Technical Conference and Exhibition, 15-17 April, Cairo, Egypt
- Publication Date
- Document Type
- Conference Paper
- 2013, Society of Petroleum Engineers
- 1.8 Formation Damage, 5.3.2 Multiphase Flow, 3.1 Artificial Lift Systems, 2.3 Completion Monitoring Systems/Intelligent Wells, 4.2 Pipelines, Flowlines and Risers, 4.6 Natural Gas, 4.3.1 Hydrates, 5.4.6 Thermal Methods, 2.4.3 Sand/Solids Control, 3.2.5 Produced Sand / Solids Management and Control, 5.6.4 Drillstem/Well Testing, 4.1.2 Separation and Treating, 3 Production and Well Operations, 5.4.2 Gas Injection Methods, 5.1.2 Faults and Fracture Characterisation, 5.4.10 Microbial Methods, 2.2.2 Perforating, 5.4.11 Cold Heavy Oil Production (CHOPS), 3.1.6 Gas Lift, 3.1.7 Progressing Cavity Pumps, 5.1.1 Exploration, Development, Structural Geology, 5.8.8 Gas-condensate reservoirs, 5.2 Reservoir Fluid Dynamics, 4.1.5 Processing Equipment, 5.2.1 Phase Behavior and PVT Measurements
- Gas Lift, Heavy Oil
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Although heavy oil producers in Block 6, Sudan have been difficult to exploit with gas lift because crude oil has 19 °API, the reservoir pressure was low, and surface dead oil viscosity ranged from 30,000 to 40,000 cp. New advances have recently been made to increase oil production. These innovative practices include:
(1). Injected condensate gas into the reservoir prior to gas lift, and soaked for a time (e.g.one day) sufficient for condensate-gas to dilute the heavy oil's API gravity, reduce viscosity, and pressurized the zone near the wellbore.
(2). Large tubing string was extended to near the bottom of perforations, gas lift valves were not utilized to ensure that a continuous volume of high-pressure condensate gas was injected into the annulus, could blend with heavy oil at the bottom hole and avoided multi-point injection caused by possible sanding.
(3). Sand trap was installed to capture the produced sand.
(4). Injection pressure and injection gas rate were optimized to produce more condensate from the gas condensate reservoir for dilution of heavy oil at the wellbore.
Field data show that these new techniques have gained excellent results, with oil gain of 6-fold compared to average oil rate by PCP.
FN field is located in the northwest region of the Muglad basin in southwestern Sudan, with area of approximate 2,471 acres. The majority of heavy oil in FN field is contained in Bentiu formation occurring at the depth of average 4,100 ft. Structurally, Bentiu pool is characterized as an elongated horst block controlled by two main normal faults (Fig.1). it has low original pressure gradient, 0.38 psi/ft, Its initial reservoir pressure ranged 1500 to 1600 psia and reservoir temperature was 147?.
Bentiu pool is characterized by a thick massive reservoir, thick bed of unconsolidated sands interbedded with thinner beds of clays in 3 to 6 ft. or less, with porosity ranging from 24.2 to 34%, oil saturation in the range of 61 to 86%, and permeability in excess of 3000 md, net oil pay thickness amounts to 90 to 130 ft. Comprenhensive geological and reservoir engineering studies indicate that Bentiu reservoir is believed to be almost homogeneous, with active bottom aquifer.
Crude oil has API gravity of 19, and dead oil viscosities vary from 6,000 to 40,000 cp at 84 ?(the annual mean ambient temperature at the field).
Commercial production in FN field began in March, 2004. Cold heavy oil production with sand (CHOPS) technology was applied in the field, and Progressing Cavity Pumps (PCPs) were installed in heavy oil wells to lift the oil due to their ability to handle sand. The pumps were all equipped with Variable Speed Drive (VSD), VSD was designed to control pump speed and production, providing PCP with smooth work for start-up, frequency adjustment for sand control and avoiding early water breakthrough caused by aggressive pressure drawdown. For those PCP wells with crude viscosities between 6,000 and 10,000 cp, The average rate of single well was 470 BOPD, In Oct. 2009, it declined to 250 BOPD per well.
However, PCP encountered some operational challenges in viscous crude wells, e.g. gas-free crude viscosities from 30,000 to 40,000 cp. PCP only worked at low frequency less than 30 Hz due to high-torque caused by viscous heavy oil compared to allowable full frequency of 60 Hz, rod parting, and high flow line pressure drop.
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