Gas Lift Workshop Doha Qatar 4-88 February 2007 Gas Lift Optimisation of Long Horizontal Wells by Juan Carlos Mantecon 1
Long Horizontal Wells The flow behavior of long horizontal wells is similar to pipelines (well horiz section) + riser (vertical section) Dynamic Simulation techniques offer the best solution: Slugging flow predictions Multiple inflow points performance relationship Limited validity of steady state techniques 2
Well Modelling Horizontal-Vertical Wells IPR 3
Well Modelling - Horizontal Wells PI Horizontal well PI is is inversely proportional to ß. The impact of ß increases as the thickness of the reservoir increases (ßh) 4
Well Modelling - Horizontal vs. Vertical PI A Steady State Equation assumes equal drainage areas 5
Well Modelling IPR Dynamic Simulation techniques Lateral wells with long horizontal wellbores require multiple inflow points and corresponding PIs Normally PI/m (or k thicknes) is available, and the PI for each section can be roughly estimated by multiplying the PI/m with the section length. Building the model using a too fine grid can result in long simulation time and too many inflow point (reservoir data) 6
Potential Problems for Stable Multiphase Flow Inclination / Elevation Snake profile Risers Rate changes Condensate Liquid content in gas Shut-in / Start up 7
Potential Problems for Stable Multiphase Flow Flow Regime Map - Inclination: Horizontal Measured & calculated SEPARATED DISTRIBUTED 8
Potential Problems for Stable Multiphase Flow Inclination impact on flow regime Pressure impact on flow regime Horizontal flow Pressure impact on flow regime Vertical flow BUBBLE BUBBLE BUBBLE SLUG FLOW SLUG FLOW 90 bar SLUG FLOW Horiz. Down Up STRATIFIED 45 bar STRATIFIED 20 bar ANNULAR Slug flow area increases with increasing upward inclination Slug flow area decreases with increasing pressure 9
Rate Changes Pipe line liquid inventory decreases with increasing flow rate Rate changes may trigger slugging Liquid Inventory Potential Problems for Stable Multiphase Flow Initial amount Amount removed Final amount Shut-In - Restart Liquid redistributes due to gravity during shut-in On startup, slugging can occur as flow is ramped up Shut-In - Restart Liquid redistributes due to gravity during shut-in On startup, slugging can occur as flow is ramped up A-Liquid Distribution After Shutdown gas liquid Flowrate Gas Production Rate 10 B-Gas and Liquid Outlet Flow
Hydrodynamic Slugging Two-phase flow pattern maps indicate hydrodynamic slugging, but pipe 1 pipe 2 pipe 3 1 2 3 a.-terrain effect and slug-slug interaction Slug Length slug length correlations are quite uncertain Frequency b.-slug distribution tracking of the development of the individual slugs along the pipeline is necessary to estimate the volume of the liquid surges out of the pipelines 11
Riser-Induced Sluging Pigging-405.plt Terrain Slugging A: Low spots fills with liquid and flow is blocked A. Slug formation Liquid seal C. Gas penetration Liquid flow accelerates B: Pressure builds up behind the blockage C&D: When pressure becomes high enough, gas blows liquid out of the low spot as a slug B.Slug production Pressure build-up Equal to static liquid head D. Gas blow-down Gas surge releasing high pressure For subsea and deepwater, the fluid behavior in the flowline and risers may actually dictate the artificial lift method, not the wellbore environment itself. 12
Slug Mitigation Method Increase GL gas rate Reduction of flowline and/or riser diameter Splitting the flow into dual or multiple streams Gas injection in the riser Use of mixing devices at the riser base Subsea separation (requires two separate flowlines and a liquid pump Internal small pipe insertion (intrusive solution) External multi-entry gas bypass Choking (reduce production capacity) Increase of backpressure External bypass line Foaming 13 A 20 km, 16 Dubar-Alwyn flowline, riser depth 250 m
Gas Lift Stability Well Modelling - Horizontal Wells H-wells allow reduced drawdown pressure, thereby maintaining the reservoir pressure above the bubble point for longer periods of time, thus reducing GORs and improving recovery H-wells producing below bubble point pressure can act as downhole separators leading to slug flow well instability occurs in long horizontal sections with upwarddownward slopes, when liquid accumulates at the low points Flow is suspected to be channeling outside the liner? 14
Well Modelling - Horizontal Wells - ER 15
Well Modelling - Horizontal Wells - ER 16
Well Modelling - Horizontal Wells - ER Blue Red Green gas oil -mixture 17
Gas Lift Stability Gas Lift Well Stability Conventional Design (unloading valves) - the well instability is dampened due to multi-point injection. Single point system (orifice) - there is a minimum surface injection rate required for the orifice to maintain sufficient annular backpressure (i.e. casing pressure consistently higher than the flowing tubing pressure) for continuous downhole gas injection. This minimum injection rate is a function of orifice size and flowing tubing pressure (wellhead pressure, PI, reservoir pressure, watercut, etc) 18
Downhole & Surface Orifice Interaction (Flow Stability) 19
Interaction Between Downhole & Surface Orifice If gas injection is not critical... Casing heading may happen To thoroughly elim inate casing heading, make the gas injection critical 20
Interaction Between Downhole & Surface Orifice Is the well unconditionally stable if gas injection is critical? Replace the orifice with a venturi 21
Gas injection rate (kg/s) Density Wave Instability 1,25 1,20 1,15 1,10 1,05 1,00 0,95 0,90 0,85 0,80 0,75 0,70 0,65 0,60 0,55 0,50 0,45 0,40 0,35 0,30 0,25 0,20 0,15 0,10 0,05 0,00 Stability map (L=2500m, PI=4e -6 kg/s/pa, P sep =10bara, 100% choke opening, ID=0.125m) Density wave instability can occur! 30 40 50 60 70 80 90 100 110 120 130 140 150 160 170 180 190 200 210 220 230 240 250 260 270 280 290 300 310 P R -P sep (bar) Because the gas-injection rate is constant, any variation in liquid inflow into the wellbore will result in a density change in the two-phase mixture in the tubing. The mixture-density change results in a change in the hydrostatic pressure drop. The mixture-density change travels along the tubing as a density wave. Increasing reservoir pressure and gas injection rate increases stability. Increasing well depth, tubing diameter, PI and system pressure decreases stability Instability occurs only when SPE 84917 PR P ρ gl Two-phase vertical flow under gravity domination often is unstable, particularly in gas lift wells. l sep < 1 22
Subsea-Deppwater Gas Lift Issues Zero Intervention Philosophy Single Point Injection Understanding the Stability Issues Using Dynamic Simulation Techniques 23
Single Point Injection Using Orifice Advantages higher reliability than conventional completion using live valves meets zero intervention philosophy set for subsea developments fewer expensive GL mandrels required (less relevant) removal of moving parts or parts that could leak eliminate risk of incorrect pressure settings on bellows 24
Single Point Injection Using Orifice Disadvantages requires a minimum gas injection rate for well stability requires a higher injection pressure valve erosion becomes an issue operating valve will have to be set higher in the well (less production rate) a well with only one mandrel will require a major well intervention should the operating valve have a problem less flexible design 25
Gas Lift Stability Horizontal Wells The primary cause of wellbore and flowline slugging is that the superficial gas velocity is too low. The addition of gas lift gas increases the superficial gas velocity and changes the multiphase flow to a more stable flow regime. Long horizontal sections give large volumes of gas and fluid which may influence each other and produce pressure variations in the wellbore and pressure fluctuations in the gas lift injection line. Condensation of water in GL injection flowline could not only cause erosion of GLVs but reduce the GL efficiency by injecting also fluids unexpected GLR. 26
Gas Lift Stability Subsea Production System Use Dynamic Simulation techniques added benefit of flow assurance analysis. When the cause of slugging flow and the severity is known, changes in design and/or producing conditions can mitigate or eliminate slugging and optimise production Evaluate optimal single point injection: Downhole Wellhead Base of riser Downhole: If max. injection pressures already predetermined, then injection depth variable. If not, injection depth in wellbore fixed as deep as possible, above 60 degree deviation. No limit for remote GLVs. 27
Long Horizontal Wells - Dynamic Simulation Techniques Application Examples 28
Horizontal Wells Modelling Sinusoidal Profile Multiple Production Zones Dynamic Well Modelling is a powerful tool for establish the potential of water accumulations in the wellbore and the effects of multiple production zones (Multilateral and SMART Wells) Potential water accumulation and backflow in the well is dictated by number and location of production zones, reservoir pressure and PI of each zone. 29
Horizontal Wells Modelling - Sinusoidal Profile WELL GEOMETRY Sensitivity simulations to investigate the effect of multiple production zones on the total well production rate The production zones can be located at the bottom and top of the well profile to maximise the effects off static head CASE RESERVOIR PRESSURE (bara) PRODUCTIVITY INDEX (sbbl/d/psi) Zone 1 Zone 2 Zone 3 Zone 4 Zone 1 Zone 2 Zone 3 Zone 4 Zone 1 300 20 Zone 1+2 300 300 20 20 1+3 300 300 20 20 1+2+3+4 300 300 300 300 20 20 20 20 PI var - RP cons 300 300 300 300 20 5 20 5 PI const - RP var 300 280 300 280 20 20 20 20 30
Horizontal Wells Modelling - Sinusoidal Profile BASE CASE 10% Watercut No gas formation occurs until an elevation of around 1,000m. For a rate of 2,500 sbbl/d the water hold-up for the downhill and uphill sections of the tubing are very similar At 5,000 sbbl/d the bottom & top of the 1 st uphill as well as the last uphill part increase. At 10,000 sbbl/d there is no slip between water and oil and an almost constant water holdup is predicted throughout the tubing 31
Horizontal Wells Modelling - Sinusoidal Profile PRUDUCTION ZONE SENSITIVITY 1000 Bbl/s, 30% Watercut Case 1-2 (Case 1 Base Case): all production comes from Zone 1 (Zone 2 locared in low point) Case 1-3: Zone 3 produces about 2/3 of the total production. Zona 1 and Zone 3 are place at the same elevation (identical Reservoir pressure and PI) Zone 1 has to deal with the frictional losses from Zone 1 to Zone 3. Case 1-2-3-4: Having all identical Reservoir pressure and PI Zone 2 and 4 behave as injection wells instead of production wells. Zone 2 water injection rate is greater than Zone 1 water production rate indicating some backflow from Zone 3 whilst still maintaining forward oil flow 1 2 3 4 32
Horizontal Wells Modelling - Sinusoidal Profile PRUDUCTION ZONE SENSITIVITY 5000 Bbl/s, 30% Watercut Due to higher total production rate, none of the wells behave like injection wells for any of the cases. 33
Horizontal Wells Modelling - Sinusoidal Profile Dynamic Simulation is a powerful tool for establish the potential of water accumulations in the wellbore and the effects of multiple production zones Potential water accumulation and backflow in the well is dictated by: number and location of production zones reservoir pressure of each zone PI of each zone. Depending on the combination of the above variables there will be periods where some backflow maybe expected into different production zones. The most significant variable is reservoir pressure. It is possible to get backflow of water only into a specific production zone whilst still maintaining forward flow of oil (slip between oil and water phases) 34
Horizontal Well Completion Design Evaluation Case description A sandwiched thin oil layer A horizontal well to be drilled Early water and gas coning at the heel might be a problem Need to evaluate three different completion designs gas oil water 35
Three different completion designs 36
Parameters for case 1 The well is 3000 m deep, has a 10 casing and a 6 tubing. Horizontal wellbore is 2500 m long, has 10 evenly distributed perforations, for each perforation, an equal PI is used (400Sm 3 /D/bar) Reservoir pressure is 200 bara (2900 psia), temperature is 100 o C, (close to the oil bubble point) Gas lift: appr. 8E5 Sm 3 /D (5 MMscfd), gas-lift valve is modeled as leak Production choke and injection choke are included On the surface, P out = 15 bara (217 psia) 37
Simulation results: pressure profile in the wellbore 200.0 199.5 Wellbore flowing pressure (bara) 199.0 198.5 198.0 197.5 197.0 Completion design 1: cemented and perforated casing Completion design 2: cemented and perforated casing + passive stinger Completion design 3: cemented and perforated casing + active stinger 196.5 196.0 0 250 500 750 1000 1250 1500 1750 2000 2250 2500 Distance from heel (m) 38
Case 2: Case description A sandwiched thin oil layer A horizontal well with smart completion design Water and gas coning is still a problem Need to avoid coning, and optimize the opening of each ICV 39
Simulation results: pressure profile in tbg & annulus 200 199 198 197 Wellbore flowing pressure (bara) 196 195 194 193 192 191 190 189 188 187 186 185 Tubing pressure Annulus pressure 0 250 500 750 1000 1250 1500 1750 2000 2250 2500 Distance from heel (m) 40
Simulation results: optimal ICV openings 1.0 0.9 0.8 0.7 ICV opening (-) 0.6 0.5 0.4 0.3 0.2 0.1 0.0 1 2 3 4 5 6 7 8 9 10 ICV ID 41
be dynamic 42 Thank You! Any Questions?