PRODUCTION AND OPERATIONAL ISSUES Dr. Ebrahim Fathi Petroleum and Natural Gas Engineering Department West Virginia University Audience and Date March 2, 2016
Summary Production and Operational Issues Shale gas reservoir production is highly rely on efficiency of hydraulic fracturing treatment and optimum operational conditions Deficiencies in planning and execution of either one results in partial or complete loss of reservoir deliverability In this lecture major factors impacting reservoir permeability and hydraulic fracture conductivity/geometry will be discussed Major production and operational issues are divided in: Pressure draw down Liquid loading Hydrate formation Infrastructure deficiencies
PRESSURE DRAW DOWN
Hydraulic fracturing Production rate q = J p Drawdown p Productivity Index = P reservoir P wf P wf Pinit h f P reservoir Horizontal well
Hydraulic fracture Conductivity (Cont.) C = fd k f w kx f f w f C fd = Hydraulic fracture conductivity k: Matrix permeability k f : Hydraulic fracture permeability x f : Hydraulic fracture half length w f : Hydraulic fracture width 2x f k f k
Pressure Draw Down 2000 1800 HCU 7-31F Tubing Press (psi) 4 Casing Press (psi) Line Press (psi) 3.5 High pressure draw down High flow rate Tubing/Casing Pressure 1600 1400 1200 1000 800 600 400 200 Csg/Tbg ratio 3 2.5 2 1.5 1 0.5 Casing Tubing Ratio Tubing pressure 0 3/6/2003 3/20/2003 4/3/2003 4/17/2003 5/1/2003 5/15/2003 5/29/2003 6/12/2003 6/26/2003 7/10/2003 7/24/2003 8/7/2003 8/21/2003 Date 9/4/2003 9/18/2003 10/2/2003 10/16/2003 10/30/2003 11/13/2003 11/27/2003 12/11/2003 12/25/2003 1/8/2004 1/22/2004 2/5/2004 0 Surface line pressure time
Pressure Draw Down (Cont.) Higher pressure draw down leads to: Higher production rate Faster pressure decline after reaching the surface line pressure Lower ultimate gas recovery (UGR) Proppant crushing and embedment Loosing hydraulic fracture conductivity Sand production and surface facility corrosion Significantly damage surface facilities specially when Ceramic proppants have been used q (production rate) High pressure draw down High flow rate Low UGR time
Proppant Placement Ideal proppant placement Real proppant placement During fracturing During Production During fracturing During Production
Proppant Crushing Embedment I Hydraulic fracture during production II III Early Time (or low pressure drawdown) Slightly impaired Fracture conductivity Mid Time (or intermediate pressure drawdown) moderate impaired Fracture conductivity Late Time (or high pressure drawdown) Highly impaired Fracture conductivity
Optimum Pressure Draw Down Optimum pressure draw down is a function of: Fracture closure pressure Proppant density, size and strength Formation mechanical properties Young's modulus and Poisson s ratio Natural fracture density Tubing pressure Optimum pressure draw down Maximum Ultimate Recovery Optimum flow rate q (production rate) Multi-stage hydraulic fracturing interactions Surface line pressure time
LIQUID LOADING
Liquid loading in a Gas Well Liquid loading is an accumulation of water, gas condensate or both in tubing. Liquids can enter the well directly from reservoir or condense from the gas in the wellbore due to pressure drop Almost always we do have liquid (water or condensate or both) production The major cause of liquid loading is low gas flow rate or velocity
Typical Gas Well History Dead well due to liquid loading Gas Rate Liquid is represented in Blue Gas is represented in Red TIME There is a critical gas velocity below which liquid can not be transferred to the surface Liquid will be accumulated at the bottom of the tubing when gas flow rate is not enough Liquid accumulation liquid loading will decrease the production rate and if not corrected kills the well
Diagnostic of Liquid Loading The easiest technique is surface monitoring High tubing/casing differential pressure High flowing bottom hole pressure Observed slugging from well Rapid increase in decline rate 300 PSI 350 PSI Low Flowing Bottom Hole pressure 600 PSI 300 PSI 600 PSI High Flowing Bottom Hole Pressure 900 PSI Normal Liquid Loading
Liquid Loading Remediation Using Velocity String Smaller size tubing Running smaller diameter tubing leads to increase in gas velocity and higher liquid lift capacity 300 PSI 600 PSI 300 PSI 350 PSI 900 PSI 600 PSI Liquid Loading Normal
Liquid Loading Remediation (Cont.) Soaping Adding surfactant at the bottom of tubing generates foaming that helps removing water build up Is not as effective in condensate loading surfactant 300 PSI 600 PSI 300 PSI 400 PSI 900 PSI 650 PSI Liquid Loading Liquid Loading
Liquid Loading Remediation (Cont.) Venting Dropping the surface pressure to atmospheric pressure to maximize gas velocity Compression Dropping the surface pressure below line pressure to increase gas velocity 300 PSI 600 PSI 14.7 PSI 100 PSI 900 PSI 650 PSI Liquid Loading Liquid Loading
Liquid Loading Remediation (Cont.) Plunger lift Using mechanical plunger to avoid liquid accumulation downhole Using Downhole pumps Plunger 900 PSI 900 PSI Liquid Loading Liquid Loading
GAS HYDRATES
Fire in Ice In essence, hydrates are ice with fuel inside they can be lit by a match! (Naval Research Laboratory)
What is a Gas Hydrate? Solid Water Structure Methane 1ft 3 hydrate at res conditions = 160 scf of gas
Flow Assurance Suitable conditions for gas hydrate formation commonly occur during hydrocarbon production, operations, where the hydrates are a major flow assurance problem and serious economic/safety concerns The gas hydrates can block pipelines Gas hydrates can damage valves, elbows, etc A large gas hydrate plug formed in a sub sea hydrocarbon pipeline (Petrobras, Brazil)(Naval Research Laboratory)
How to Reduce Gas Hydrate Problems At fixed pressure, operate at temperatures above the hydrate formation temperature. This can be achieved by insulation or heating of the equipment At fixed temperature, operating at pressures below hydrate formation pressure Dehydrate, i.e., reduce water concentration to an extent of avoiding hydrate formation Use chemicals such as methanol and salts for the inhibition of the hydrate formation conditions Prevent, or delay the hydrate formation by adding kinetic inhibitors Prevent hydrate clustering by using hydrate growth modifiers or coating of working surfaces with hydrophobic substances
INFRASTRUCTURE DEFICIENCIES
Pipeline Design Surface pipelines are designed based on production forecasts Inaccurate production forecast leads to large pipe size design that is costly and not economical (optimistic production forecast) smaller size pipeline design which is not able to deliver real field production (pessimistic production forecast)