PL3. COMPLETION DESIGN
4. CORE ANALYSIS Reference 1. The Completion engineer should check the availability of formation
4.8. Reduction of permeability during production
4.8.1. Obstructions may occur also during production phase and caused by the following.
4.8.2. Produced fines.
5. STRATEGY TO MINIMISE THE SKIN EFFECTS Reference
5.1. In a radial flow situation, where fluids move towards the well from all directions, most of the pressure drop in the reservoir occurs fairly close to the wellbore. In a uniform sand, the pressure drop across the last 15ft of the formation surrounding the wellbore is about one half of the total pressure drop from the well to a point 500ft away in the reservoir. Obviously flow velocities increase tremendously as fluid approaches the wellbore. This area around the wellbore is the ‘critical area’ and as much as possible should be done to prevent damage or flow restrictions in this critical area.
5.2. If a well is to be perforated overbalanced, then strict control over the fluid used to ensure it is compatible with the reservoir formation, formation fluids and must also be clean to prevent formation damage.
5.3. Phasing P-1-M-7100 9.3.1
5.4. Gun stand-off P-1-M-7100 9.3.1
5.5. Use of clean tubular goods.
5.6. Maximise the perforated zone within the net pay. P-1-M-7100 9.3.1 5.7. Use of underbalance perforating practice. P-1-M-7100 9.3.2
5.8. Use of maximum shot density. P-1-M-7100 9.3.1
5.9. Perforating tunnels should be large and deep enough to prevent any restriction to flow.
5.10. Gravel Pack Completions
Due to the problem of flow restriction the important factors are:
• Hole diameter to achieve adequate flow area.
• Shot density to achieve adequate flow area.
• Debris removal.
• Shot phasing.
This in conjunction with correct gravel pack procedures is essential for to prevent high skin factors.
5.11. Specific chemical treating of the near wellbore area to remove formation damage.
5.12. Limit brine volume losses in depleted reservoir and use surface tension reducer.
6. WELL INFLOW PERFORMANCE Reference
6.1. The inflow performance relationship (IPR) provides the flow potential of the reservoir into the wellbore against the resistance to flow of the formation and near wellbore region. The theoretical IPR is an idealistic assumption of flow performance without pressure drop due to skin effect in the near wellbore region and governed only by the size, shape and permeability of the producing zone and the properties of the produced fluids.
6.2. The equation used shall take into account all the Darcy and non-Darcy effects.
6.3. Where inflow relationship passes through the bubble point, a straight line IPR is drawn above the bubble point and the curved IPR signifies the two phase flow below this point. For this, Vogel’s equation is combined with the PI to develop a general IPR equation. This has been published by Brown. When the BHFP is above the bubble point use the normal straight line equation:
o Jp p
q = −
and when it drops below the bubble point use the modified Vogel equation:
6.4. Fetkovich recognised that many oil wells could be handled in the same way as gas wells using the curved IPR:
o Cp p
q = −
C = Linear deliverability coefficient n = Deliverability exponent (0.5 to 1.0)
6.5. Blount and Jones presented an alternative generalised IPR equation which was an extension to the Forcheimer equation to include the non-Darcy flow effects:
R p aq bq
p − = +
6.6. Forcheimer equation for gas wells should be used for pressure below 2,000psi and where the drawdown is small as in high permeability wells:
2 g g wf
R p Aq Aq
p − = +
6.7. When the µz value is not constant the pseudo pressure m(p) shall be used instead of P².
Pseudo pressure m(p) shall be used when pressure is above 2,000psi and in low permeability wells where drawdown greater than 500psi is expected.
‘Completion Design Manual’ STAP-P-1-M-7100
Figure PL 3.3 - Reservoir Pressure Trends For Various Drive Mechanisms
Figure PL 3.4 - Gas-Oil Ratios Trends For Various Drive Mechanisms
PL. 3.5. TUBING PERFORMANCE
1. GENERAL Reference
1.1. The relationship between pressure and temperature drop in wells and PVT behaviour is complex. Pressure drop is determined using empirical and semi-empirical correlation’s and carried out on computer software programmes.
1.2. Calculating pressure drop in tubing involve numerical integration of the steady-state pressure gradient equation over the entire tubing length. It consists of the following three components:
• Hydrostatic head
• Wall friction
• Fluid acceleration.
1.3. The acceleration term is usually negligible except in system involving significant fluid expansion (gas wells when near atmospheric pressure).
1.4. The friction losses are controlled by fluid viscosity and geometric factor (pipe diameter and roughness) and normally accounts for around 10 % of overall head losses.
1.5. The gravitational component accounts for around 90 % of the overall head losses and is proportional to the density of the fluid mixture at each point in the tubing and is a complex function of the relative velocity of the phases present.
1.6. The geometrical distribution of the gas and liquid in the pipe constitute the “flow pattern” or “flow regime”. The flow patterns are governed by the flow rates of each phase, the tubing diameter and to a lesser extent PVT fluid properties.
1.7. Flow patterns are identified using empirical flow pattern maps. Each flow regime has different pressure gradients that should be calculated by the use of different empirical correlation for liquid hold-up and friction factor.
1.8. Typical pressure gradients in wells for different flow patterns are:
• Single phase oil = 0.36psi/ft
• Bubble flow = 0.25psi/ft
• Slug flow = 0.20psi/ft
• Mist flow = 0.1 - 0.2psi/ft
2. TEMPERATURE GRADIENT Reference